CHAPTER ONE

1.0 Introduction.

One only has to experience a power outage to be reminded of the role electricity play in every sphere of human endeavour. Our lightening, heating, cooling will no longer operate television, computers and other communication systems become unusable. Even industries, schools and commercial buildings will become virtually inoperable.

The need to develop a sustainable power generation in order to meet the growing demand of both domestic and industrial activities in the Nigerian energy sector has brought about the idea of designing a power plant. A power plant is an assembly of systems or subsystems to generate electricity. It may be defined as a machine or assembly of equipment that generates and delivers a flow of mechanical or electrical energy. The main equipment for the generation of electric power is a generator.

Power Plant classification.Power plants are primarily determined by the type of prime mover they use. Varieties of power plant exist and these are as outlined below:

(a) Conventional power plantSteam Engines Power PlantsSteam Turbine Power PlantsDiesel Power PlantsGas Turbine Power PlantsHydro-Electric Power Plants

(b) Non conventional Power PlantNuclear Power Plants Thermoelectric GeneratorTherm-ionic generatorFuel-cells Power PlantsPhotovoltaic solar cells Power SystemMH D Power PlantsFusion Reactor NPP Power S y stemBiogas, Biomass Energy Power systemGeothermal EnergyWind Energy Power SystemOcean Thermal energy conversion (OTEC)Wave and Tidal WaveEnergy Plantation Scheme

BRIEF OVERVIEW OF POWER GENERATION IN NIGERIA.

Power generation in Nigeria can be historically traced back to 1898 when the first generating plant was installed in the city of Lagos. From then, until 1950, the pattern of electricity development was

in the form of individual electricity power undertakings scattered all over the country .By 1950, the integration of electricity power development lead to the passage of the ECN (Electric Corporation of Nigeria) ordinance No 15 of 1950.The ordinance enabled electricity department and all other undertakings to come under one body. The ECN and NDA (Niger Dam Authority) were merged to form the National Electric Power Authority (NEPA) which took effect from first of April’ 1972.What is currently called Power Holding of Nigeria was an offshoot of NEPA. The electric Power sub sector is dominated by the Power Holding of Nigeria. The PHCN co-exist with Independent Power Producers (IPP), some of which has its power purchase agreement.

Following the introduction of electric power sector reform Act in 2005,NEPA was transformed into a holding company which was subsequently unbundled into eighteen(18) companies including 6 power generation plants,11 distributors and 1 transmission company. The power sector reform initiated in 1999 has introduced a new set of players (IPPs).Currently, about 29 power generation licenses have been granted to IPPs by the National Electricity Regulatory Commission (NERC) since 2006.

Till date, Nigeria has about 6,380MW of installed electric power generation capacity consisting of three hydropower plants and six thermal power plants. These include the following:Afam electric power unit Delta electric power business unit Egbin electric power business unit Jebba hydropower station Kainji hydropower stationSapele electric power business unit Shiroro hydropower business unitMambila hydropower plant

CHALLENGES AND PROSPECTS OF THE NIGERIAN POWER SECTOR.

Nigeria is currently facing a serious energy crisis. Power outages are more frequent than ever and the energy sector operates well below its capacity. The Nigerian Power Holding Company, which is in charge of the sector is grossly inefficient. Various power projects have been embarked upon over the years. Some of which include the following:

A 400MW gas turbine power plant in Afam, under the federal government shell agreement which was later expanded to 900MW capacity in 2001.A 480MW integrated cycle electric power plant built by ENI of Italy and operating on a two gas turbine and one steam turbine, which was inaugurated in April 1, 2005 at Okpai, in Delta state.A 3-335MW gas fired turbine power plant built by Chinese firm (CMEC) in Okitipupa effective from November 1, 2002.A 3,960MW hydropower plant project approved by the government to be constructed on the Mambila Plateau in North -East Nigeria

In addition to the above various initiatives, several independent power plant projects have equally been embarked upon in order to harness the Nation’s oil and gas potentials and bridge the gap of energy demand in Nigeria.

PROBLEM STATEMENT

The importance of electricity as it reflects in our day to day activities cannot be overemphasized. Nigeria’s demand for energy is estimated to be 7,600 (MW). However, the country only has a total installed generating capacity of 6,000MW, which is far from being optimized as the country is only able to achieve 3,000MW output (Nigerian Energy Report, 2009). In order to ameliorate the power crisis being faced in the energy sector in Nigeria and Kaduna in particular, there is need to embark on an increased power generation drive which will also serve as part of the roadmap for the attainment of the Nigerian Energy Vision 2020. This has lead to the development of a blueprint for the design of a 200MW oil fired power plant to be cited in Zungeru axis of Kaduna.The power plant will be steam driven due to its economic scale. The choice of Kaduna for its location is born out of the fact that cheap source of fuel (low pour fuel oil) can be made readily available from the Kaduna Refining and Petrochemical Company. The fuel delivery mode will be by pipeline facilities. The Zungeru site has been chosen due to its vast land and hydrological resources with a capacity of sustaining well above 900MW power plant water requirements as indicated by table 1a, according to the Nigerian Energy Report.

Surveys and review of maps, aerial photographs have been carried out in order to determine available data on soil, vegetation and land use. Further efforts have also been made to ascertain the existing water-ways, accessibility to adequate transmission lines, and provision for combustion waste disposal, land availability, environmental impact and availability of workforce.

Table 1a-Estimate of current exploitable hydropower sites in Nigeria (From Nigerian Energy Report).

SCOPE AND LIMITATION OF PROJECT.

The design of a 200MW oil fired power plant within the framework of an academic research involves some level of assumptions. However, this project will be target specific and will tend to address key components in the design of a 200MW oil fired power plant. Considerations shall be given to the following plant parameters which will serve as the design limits to be observed:

The project shall take into account the site selection for power plant erection.The design, specification and selection of boilers for setting up the power plant.The prime movers (steam turbines) parameters shall be duely considered with emphasis on its design, specification and selection process.Process condenser design and selection with due recourse to prevailing ambient conditions in Kaduna.Cooling and circulation water supply and requirements (make up, treatment etc).Cooling tower design, specification and selection.Fuel oils selection, characteristics and analysis of air- fuel system for boiler load optimization shall be considered.Feed water heating design and selection.Heat balances, plant cycle analysis and plant requirements.plant citing parametersHowever, the following will not be included in the scheme of project: the details of civil-structural, mechanical and chemical designs, ancillaries such as pipe, valves and insulation, jacketing details, instrumentations and controls, detailed corrosion protection measures, detailed emission controls and flue gas analysis .

SIGNIFICANCE OF DESIGNING A 200MW POWER PLANT IN KADUNA.

Kaduna and indeed Nigeria at large have been grappling with an epileptic power supply over the years. This has taken a toll of both domestic and industrial activities. More worrisome is the closing up of our textile companies, majour manufacturing companies such as Michelin, Dunlop and others (which in the past accounted for over 15 percent employment generation in the country) due to unstable power situation.

There is need to increase the power generation capacity in addition to improving the capacity utilization of the existing ones in Nigeria. The design and citing of a 200mw oil fired power plant could not have come at a better time most especially when viewed against the backdrop of energy crisis rocking our nation. Moreover, with the PHCN available energy statistic showing 4,428mw as current power generation capacity as against the Nigerian energy vision 2020 target of 6000mw by 2010 and 10,000mw by December,2011, the 200mw power plant plan will further complement the attainment of this drive and help in reducing the existing energy gap.

The choice of Kaduna for citing the power plant was well conceived in that the source of fuel supply can be readily made available through piping facilities or otherwise from the Kaduna Refining and Petrochemical plant .In addition to this, cooling water and other process water requirements can be

met from the primary plant citing-Zungeru which has a proven record with the capacity to sustain a 500mw power plant utility water requirements (according to the National Energy Commission report).

OBJECTIVE OF THE STUDYThe objective of the project is to design a 200MW oil fired power plant to be situated in Kaduna in order to boost the power generation capacity of Nigeria at large.

JUSTIFICATION OF THE STUDY.

Studies of power plant by different researchers have been an interesting feature of the Nigerian energy sector. The concept itself is by no means a new technology. However, what may be new is its domestication and adaptation to suit the present day realities in Kaduna environs. The reasons for embarking on this project are not far-fetched: There is an urgent need to address the shortfall in the energy sector through the development of power generation scheme.Though, intense power sector reforms are currently being engineered nation-wide as revealed by studies, very little has been done to harness the abundant potentials resident in Kaduna in terms of industry based fuel source from the Kaduna Refining and Petrochemical Company and vast hydrological resources in Zungeru. A steam driven power plant with an oil based firing method has the capacity to generate over 3000MW power plant as compared to any other conventional power plant scheme (Diesel, gas).This will, no doubt, have a far reaching effect on ameliorating the energy crisis in Kaduna ailing industries and its environs.It requires less space when compared with hydro power plant and has lower cost of generation as compared with diesel power plant.Furthermore, steam power plants have lower installation cost, with readily available components and has the capacity to generate higher employment opportunities.

REFERENCES

Nigeria’s Dual Problems: Policy Issues and Challenges. International Association for Energy Economics, Akin Iwayemi.Power Sector Reforms in Nigeria; O.I Okoro, I.P Govenderand E. Chikumi.National Energy Databank, www.energydatabank.org.Power Plant Engineering, Black and Veatch-1996.Wikipedia, the free encyclopedia.www.wikipedia.com

LITERATURE REVIEW

2.0 INTRODUCTION.

It is no exaggeration that the whole mankind, indeed the entire world economy are today governed by the forces of electricity. (Engr.M.N Manata, 1979-The development of electricity in Nigeria, 1896-1972).The drive for achieving energy sufficiency on a sustainable platform in Nigeria and Kaduna in particular has been the motivating factor behind the current studies in power plant.

2.1 HISTORICAL REVIEW OF POWER PLANT.

Early studies showed that Thomas Savery (1650–1715) and Thomas Newcomen (1663-1729) designed and developed the first steam power plant. See figure 1. The limitation of their studies was that the power plant was used to pump water from mines, so that coal could be brought up from a greater depth, previously inaccessible. A lot of energy was wasted and this resulted in very low plant efficiency. James Watt (1736–1819) furthered the advances in the development of steam power plant by designing a separate cooler (condenser) into which the steam is injected before being sent back to the boiler. The Watt’s engine was employed in driving locomotives, ships etc.(fig 2.2)

Figure 2.1-Thomas Savery and Newcomer plant.

Fig2,2

2.2 CURRENT ADVANCES IN POWER PLANT IN NIGERIA

Hitachi engineering company.(1985) under the auspices of the Nigeria Electric Power Authority(now PHCN) designed the Egbin power plant which was commissioned in 1985 with an initial two 220MW steam turbines, each having its own dual fuel gas/oil fired boiler. This was later upgraded to 6-220MW steam turbines bringing it to a total of 1,320MW in 1987.

Chiyoda Chemical Engineering Company (1978) designed a four 14MW steam turbine generator power plant for the Kaduna Refining and Petrochemical Company in 1978 .The power plant operates on a dual fired(fuel gas/heavy oil) 5 water tube boilers with each having a steam capacity of 120 tons/hr at 412°C and 42.5kg/cm2 .

2.3 REVIEW OF STEAM POWER PLANT COMPONENTS.

The steam power plant is an integration of various components. A typical steam plant is illustrated in fig 2.2.Studies have shown that a steam power plant must meet the following requirements:1. Furnace to burn the fuel.2. Steam generator or boiler containing water. Heat generated in the furnace is utilized to convert water in steam.3. Main power unit such as an engine or turbine to use the heat energy of steam and perform work.4. Piping system to convey steam and water.

In addition to the above equipment the plant requires various auxiliaries and accessories depending upon the availability of water, fuel and the service for which the plant is intended.The flow sheet of a thermal power plant consists of the following four main circuits:(i) Feed water and steam flow circuit(ii) Fuel and fuel handling with waste disposal circuit(iii) Air and gas circuit(iv) Cooling water circuit.A steam power plant using steam as working substance works basically on Rankine cycle. Steam is generated in a boiler, expanded in the prime mover (steam turbine) and condensed in the condenser and fed into the boiler again.The different types of systems and components used in steam power plant are as follows:(i) High pressure boiler(ii) Steam turbines(iii) Condensers and cooling towers(iv) Fuel handling system. E.g. fuel oil, coal, fuel gas(v) Flue gas, ash and dust handling system(vi) Draught system(vii) Feed water purification plant(viii) Pumping system(ix) Air preheater, economizer, super heater, feed heaters.

Fig 2.2 A pulverized coal fired steam power plant

2.3.1 STEAM GENERATORS

A steam generator is a device that generates steam at the desired rate, pressure and temperature. It is a complex integration of furnace, superheater, reheater, boiler or evaporator, economizer and air preheater along with various auxiliariessuch as pulverizers,burners,fans, stokers,dust collectors and precipitators,ash handling equipment and chimney or stack. The thermal structure of a typical boiler is shown in figure 2.3 while the component structure is given in figure 2.4

Fig 2.3 Thermal structure of a boiler furnace (APH – air preheater, EPS – electrostatic precipitator, ID fan – induced draft fan, LTSH – latent superheater, platen SHTR – platen superheater, RHTR – reheater,SH – superheater)

2.3.1.1 STEAM GENERATOR CLASSIFICATION.

Steam generators or boilers come under various classifications. From the viewpoint of applications, they can be (i) utility steam generators (ii) Industrial steam generators (iii) marine steam generators.Utility steam generators are those used by utilities for electric power generating plants. They can be either subcritical (steam pressure below 221.2 bar) or supercritical (above 221.2 bar).Subcritical steam generators are water tube drum type and their operating is between 130 to 180 bar steam pressure. The supercritical steam generators are drumless once-through type and operate at 240 bar pressure or higher. Most utility steam generators are of 170-180 bar water tube –drum variety, which produce superheated steam at about 540-560°C with one or two stage reheat and steam capacities of 120-1300 kg/s with power plant unit output of 125-1300MW. They come in straight, bent (best orientation) or cross tube orientation with either natural (for boiler pressure below 180 bar) or forced circulation system (pressure above 180 bar). They can be single, double or four drum boiler. They can be either fired by pulverized coal or heavy oilIndustrial steam generators are those used in process industries like sugar, paper, institutions, commercial and residential buildings. They are smaller in size and operate at 5-105 bars with steam capacities up to 125 kg/s.They do not produce superheated steam but rather supply wet or saturated steam.Marine steam generators are used in mainly marine ships and ocean liners driven by steam turbine. They are usually oil fired and they produce superheated steam at about 60-65 bar and 540°C.

They can also be classified according to the relative flow of products of combustion or flue gases or water. While fire tube boiler have its products of combustion (hot flue gas) flowing through tubes

surrounded by water in a shell, the water tube boiler is designed to allow water from a drum flow through the tubes and the hot flue gases flow over it. Further classification is given in figure 2.5

Fire tube boilers are suitable for small steam requirement with operating limits of 18 bar and 6.2 kg/s steaming capacity. Though they have low first cost, less draught and skill requirement and reliability in operation, there application is limited to saturated steam production in industrial plant. They are no longer used in utility plant. The following are the obvious advantages of water tube boiler over fire tube boiler:

MERITS OF WATER TUBE BOILERS OVER FIRE TUBE BOILERS 1. Generation of steam is much quicker due to small ratio of water content to steam content. This also helps in reaching the steaming temperature in short time.2. Its evaporative capacity is considerably larger and the steam pressure range is also high-220 bar.3. Heating surfaces are more effective as the hot gases travel at right angles to the direction of water flow.4. The combustion efficiency is higher because complete combustion of fuel is possible as the combustion space is much larger.5. The thermal stresses in the boiler parts are less as different parts of the boiler remain at uniform temperature due to quick circulation of water.6. The boiler can be easily transported and erected as its different parts can be separated.7. Damage due to the bursting of water tube is less serious. Therefore, water tube boilers are sometimes called safety boilers.8. All parts of the water tube boilers are easily accessible for cleaning, inspecting and repairing.9. The water tube boiler's furnace area can be easily altered to meet the fuel requirements.

Fig.2.4 Nomenclature of a typical boiler

Figure 2.5 gives a detailed classification of steam generators.

2.3.2 STEAM GENERATOR COMPONENTS.

2.3.2.1 SUPERHEATER

A superheater is utilized to remove the moisture content in the steam by raising the temperature while keeping the pressure constant. Steam that undergoes this process is referred to as superheated steam. Superheating improves the turbine internal efficiency and hence the lifetime of the turbine. A superheater therefore increases the capacity of the plant, reduces corrosion of the steam turbine and reduces steam consumption of the steam turbine. Superheaters are classified into three types- Radiant superheaters, Convective superheaters and Combined radiative and convective superheaters.Convective superheaters are normally called primary superheaters and are located near the convective zone of the furnace, whereas radiant and combined superheaters are termed secondary superheaters. Superheaters are often divided into more than one stage such as:A platen superheater 2. A pendent superheater 3. A horizontal superheater 4. A radiant superheaters. Figure below gives the arrangement of platen, pendent and convective superheater.

The radiant superheaters receive energy by thermal radiation from the furnace and are located close to the furnace exit. The convective superheater is located in a low-gas temperature region ranging from 423 to 813K lower, depending on the degree of superheating required. It is shielded by several rows of screen tubes and the gas is well mixed and cooled before it encounters the superheater.

However, Pendent superheaters receive heat by both convection and radiation; they are normally hung from the top of furnace usually located in the crossover duct between the furnace and the back pass.The outside tube diameters of the pendent superheaters normally falls in the range 32–51mm and the tube thickness is usually in the range 3–7mm. The platen superheaters are made from flat panels of tubes located in the upper part of the furnace, where the gas temperature is high. The tubes of the platen superheater receive very high radiation. The mass flow velocity of steam in the platen superheater is normally in the range 800–1000 kg/(m2 s). The outer diameter of the platen superheater tubes is in the range 32–42 mm. The number of parallel tubes in a platen is generally 15–35, depending on the design steam velocity.

Fig 2.6 arrangement of platen superheater

2.3.2.2 REHEATERS

The reheater is usually located above the primary or convective superheater in the convectivezone of utility boilers. A schematic view of a convective reheater is shown in Fig.2.8. The pressuredrop inside the reheater tubes has an important adverse effect on the efficiency of the turbine. The pressure drop through the reheater should be kept as low as possible. The tube diameter of the reheater is normally 42–60mm and the overall heat transfer coefficient is 90–110W/(m2 K).

Fig 2.7 pendent superheater

Fig 2.8 schematic diagram of a reheater.

2.3.2.3 ECONOMIZERThe feedwater from the first high-pressure heater passing through a heat exchanger and heats up to the saturation temperature corresponding to the boiler pressure. This heat exchanger is normally called the economizer; it extracts waste heat from hot stack gases to heat the feedwater to the desired saturation temperature, hence the energy input to the boiler increases and the efficiency as well as economy of the power plant increase. The economizer is generally placed between the convective superheater and the air preheater. Economizers are designed for downward flow of gas and upward flow of water, consisting of more than 250–300 coils in a staggered arrangement in a single bank.

Figure 2.9 depicts the arrangement of the economizer. The materials are usually of steel tube- type economizers. The outside diameter of the economizer tubes is normally in the range 25–75mm and the tube thickness is 3–5mm.

Fig 2.9 Arrangement of economizer

FEED WATER HEATERS

Feedwater heaters are used to raise the temperature of the water or to increase the mean temperature of heat addition in the cycle before it enters the boiler. The feedwater heater utilizes the steam which is extracted along the turbine expansion line for water heating. Feedwater heaters are used in a regenerative feedwater cycle to increase thermal efficiency and thus provide fuel savings.Feedwater heaters are normally classified into two types:.1. Open feedwater heaters 2. Closed feedwater heaters.Closed Feedwater Heater (Heat Exchange Institute Standards for Closed Feedwater Heaters. ASME Boiler and Pressure Vessel Code, Sec. VIII,2000 ) is a shell-and-tube heat exchanger that warms feedwater by means of superheated steam or dry saturated or wet steam. Normally water flows inside the pipe and steam flows on the shell side. The number and types of heaters usually employed are: (1) plant sizes of up to 70 mW, two closed low-pressure heaters, one open heater, one closed high-pressure heater; (2) plant sizes of 75 to 300 mW, two or three closed low-pressure heaters, one open heater, two closed high-pressure heaters; (3) fossil-fueled plant sizes above 300 mW, three or four closed low-pressure heaters, one open heater, two or three high pressure heaters. Table 1a gives the general range of feedwater selection for various power plant sizes.Minimum heater cost prevails with minimum restrictive specifications, e.g., horizontal, two-pass, high water velocity (10 ft/s at 60_F), no length limits. Overall heater length is limited by maximum available tube lengths of 100 ft for copper alloys, admiralty metal, and copper-nickel and 85 ftfor Monel. With U-tube construction, this results in heater lengths of about 48 and 40 ft, respectively. A general rule, to ensure good steam distribution, is that the length in feet shall not exceed the shell diameter in inches plus 2; i.e., with a 30-in diam shell, the length should not exceed 32 ft.

Pressure drop through the tubes must be economically evaluated as it varies approximately with the square of the water velocity.If a length restriction is imposed, the designer may have to substitute a four-pass arrangement for the two-pass design, with consequent large diameter shell and water chamber, heavier walls, more tube holes to be drilled, more tubes to be installed, and a cost increase. If a pressure-drop restriction is imposed, a lower water velocity results, with more tubes, larger shell and chamber diameter, and more surface because of the lower heat-transfer rate. Vertical heaters, with appropriate construction details, are also higher in cost. Fig 2.10 gives a diagram of a typical close feed water heater. According to the method of releasing the drain, closed feedwater arrangements are further classified into two types:1. Drain cascaded forward2. Drain cascaded backward

Table 1a-Nos of feedwater heaters

Fig 2.10a condensing heater.

In open feedwater heaters, heat transfer takes place by direct mixing of steam and water. Normally open feedwater heaters are more efficient than closed feedwater heaters. Though the efficiency of open feedwater heater is higher, closed feedwater is normally used for modern power plants utilizing a large number of feedwater heaters to avoid a large number of pumps at each entrance and exit of the heater. Deaerators or deaerating heaters are also another form of open feedwater heater but they serve the following functions (1) to degasify feedwater and thus reduce equipment corrosion (2) to heat

feedwater regeneratively and improve thermodynamic efficiency and (3) to provide storage, positive submergence, and surge protection on the boiler feed-pump suction.Removal of oxygen and carbon dioxide from boiler feedwater and process water at elevated temperature is essential for adequate conditioning.A modern deaerator will, by mechanical action, reduce O2 content of effluent to less than 0.005 cm3/L and CO2 content to a negligible amount. Water must (1) be heated to and kept at saturation temperature, as the gas solubility is zero at the boiling point of the liquid, and (2) be mechanically agitated by spraying or cascading over trays for effective scrubbing, release, and removal of gases. Gases must be swept away by an adequate supply of steam. Since the water is heated to saturationconditions, the terminal temperature difference is zero with maximum improvement in associated turbine heat rate. There are two majour types of deaerator: spray and tray-type deaerator. The tray type is prevalent (Fig.2.10b) .While it has some tendency to scale; it will operate at wide load conditions and is practically independent of water-inlet temperature. Trays can be loaded to some 10,000 lb/(ft2 _ h), and the deaerator seldom exceeds 8 ft in height.The spray type uses a high-velocity steam jet to atomize and scrub the preheated water. Applications are (1) marine service, where it is unaffected by ship roll and pitch, and (2) industrial plants where operating pressures are stable. It requires a temperature gradient, e.g., 50_F minimum, toproduce the fine sprays and vacuums with the cold water required.

Fig 2.10b Tray type deaerator

AIR PREHEATERS The flue gas leaving the chimney is normally in the range 280–480 ◦C. leaving the flue to the atmosphere at this high temperature causes high energy losses. Air heaters are used to utilize this hot flue gas to heat the air required for combustion, and lead to an improvement in combustion efficiency. Since this is a gas-to-gas heat exchanger, its heat transfer surface area is extremely large. There are two different types of air pre heater. These are recuperative and regenerative air preheatersRecuperative Air Preheater: A recuperative air preheater is nothing but a shell-and tube heat exchanger in which hot flue gas flows inside the tubes and air flows outside. Since this is a gas-to-gas heat exchanger it requires a huge heat transfer surface area and hence larger size.

Rotary or Regenerative Air Preheater: Rotary preheaters works on the counterflow principle, and consist of a rotor and housing. The rotor is normally divided into 12–24 radial divisions of heat transfer elements and is made up of steel sheets. The rotor is driven by an electric motor and is coupled with worm-gear drive that helps to reduce the speed of the rotor device to 2–6 rpm. During the rotation through the flue gas side the heat transfer element absorbs heat which is later given off during the rotation through the air section. Based on the number of sections rotary preheaters are further classified into three types: bisector, trisector, and quadsector types. Trisector-type air preheaters are divided into three sections: one for the flue gas, one for the primary, and one for the secondary section. In the quadsector type, the secondary air section is divided into two sections, taking up primary air. Figure 2.11 gives an example of a rotary air preheater.

Fig 2.10 Isometric view of Rothemuhle air heater (From Babcock & Wilcox, Brochure)

Although rotary air preheaters are compact heat exchanger with a large heat transfer surface, relatively cheap and have good heat transfer characteristics, they have some drawbacks. These include flow openings being plugged by fly ash, sealing of gas to air path and large pressure drop for both air and gas.When air is required to be heated up to 400-C or above, two stages of air preheating are normally used with an economizer installed in between the two air preheaters. The first air preheaters may be tubular while the second one rotary

Fig 2.11 Bisector Ljungstrom air preheater isometric cut-away view. (From ABB Air Preheater, Inc. Used with permission.)

STEAM TURBINES.

The steam turbine generator is the primary power conversion component of the power plant. It is a prime mover which continuously converts the energy of high pressure, high temperature steam supplied by a steam generator into a shaft work with the low temperature steam exhausted to a condenser. The function of the steam turbine generator is to convert the thermal energy of the steam from the steam generator to electrical energy. Two separate components are provided: the steam turbine to convert the thermal energy to rotating mechanical energy, and the generator to convert the mechanical energy to electrical energy. Typically, the turbine is directly coupled to the generator. The operation of the steam turbine generator involves the expansion of steam through numerous stages in the turbine, causing the turbine rotor to turn the generator rotor. The generator rotor is magnetized, and its rotation generates the electrical power in the generator stator.

2.4.1 TURBINE CLASSIFICATION.Turbines can be classified, depending on the types of blades used and the method of energy transfer from the fluid to the rotor wheel. It could be impulse or reaction stage turbine or a combination of both types.

Impulse Stage. An impulse stage consists of a stationary nozzle with rotating buckets or blades (Fig 2.12).The steam expands through the nozzle, increasing in velocity as a result of the decrease in pressure. The steam then strikes the rotating buckets and performs work on the rotating buckets, which in turn decreases the steam velocity. The impulse stages can be grouped together in velocity compound stages or pressure compound stages (Fig. 2.13). The velocity compound stage involves a stationary nozzle followed by several rotating and stationary buckets. The nozzle has a large pressure drop with a resulting increase in velocity. The first set of rotating buckets partially decreases the velocity as a result of the work performed on the buckets. The steam then passes through a set of stationary buckets in that the steam direction is changed back to the original direction. The steam then enters a second set of rotating buckets where the steam velocity is completely dissipated by performing work on this row of buckets. The velocity compound stage can consist of the stationary nozzles and many rotating and stationary buckets; however, there usually are only two rotating bucket rows and one stationary bucket row. The velocity compound stage typically is used as the first stage of a turbine because of its ability to withstand high pressure reductions and the resultant efficiency in quickly reducing pressure and minimizing the requirements for high pressure casings. The velocity compound stage is also called a Curtis stage.In a pressure compound series of impulse stages, rather than involving a large pressure drop in the one nozzle set, the pressure compound stages involve several sets of nozzles with small pressure drops through each set of nozzles and complete velocity dissipation in each row of rotating buckets. The pressure compound stages are also called Rateau impulse stages.

Reaction stage: In a reaction staging, this consists of both rotating and stationary nozzles. This is shown in figure 2.14 .The steam expands through the stationary nozzles with an increase in velocity. The steam then enters the rotating nozzles where it expands further. The velocity force from the initial expansion and the expansion in the rotating blades is imparted to the rotating nozzles.The expansion of the steam in the stationary nozzles of the reaction turbine is an impulse action. Therefore, the reaction stage in actual turbine applications is a combination of impulse and reaction principles. The reaction turbine is classified as percent reaction by the amount of energy conversion in the rotating nozzles. The term reaction stage generally implies a stage where 50% of the pressure drop occurs in the rotating blade and 50% occurs in the stationary nozzles. The reaction stage has pressure drop across the rotating blades, inducing axial thrust in the rotor which is offset by balancing pistons.

Fig 2.12 Simple impulse turbine stage. (From GP Publishing. Used with permission.)

Fig 2.13 Velocity compounded and pressure compounded turbine. (From GP Publishing. Used with permission.)

Fig 2.14 Reaction turbine stages. (From GP Publishing. Used with permission.)

TURBINE TYPES

Steam turbines are divided into many types with various designations. The designations may indicate the various combinations of turbine types that make up a turbine as well as the turbine size. From 500 to about 2500 kW rated capacity, turbine generators will usually be single stage, geared units without extraction openings for either back pressure or condensing service. Rated condensing pressures for single stage turbines range from 3 to 6 inches Hga. Exhaust pressures for back pressure units in cogenerationservice typically range from 15 psig to 250 psig. Figure 2.15 shows various representative turbine types. The commonly used turbine types are described with the following designations:Pressure-Reheat Designation: The designation of a turbine by a pressure may also involve the cycle arrangement with regard to reheat. Small units without reheat, the steam turbine may consist of a single turbine with the steam flow entering the turbine, expanding through the turbine, then exhausting either to a condenser or to a process line. This is a straight-flow turbine as shown in Figs. A) and (B). For a large unit without reheat, the steam may expand through an initial section and then exhaust to another turbine. This later turbine may then exhaust to a condenser or to a process. In this arrangement, the initial turbine is designated the high pressure turbine and the second turbine the low-pressure turbine, as shown in Fig.2.15(C).For a single reheat cycle, the steam from the boiler flows to the high-pressure turbine where it expands and is exhausted back to the boiler for reheating. The reheat steam coming from the boiler flows to the intermediate-pressure or reheat turbine where it expands and exhausts into a crossover

line that supplies the steam to the low-pressure turbine. The steam expands through the low-pressure turbine and exhausts to a condenser. Thus, the single-reheat cycle has high-, intermediate-, and low-pressure turbine sections as shown in Fig. 2.15(D). The designation is based on the location of the turbine in the cycle relative to inlet pressure. The intermediate-pressure turbine also is called the reheat turbine since it receives the reheated steam.For a double-reheat cycle, the steam from the boiler flows to the high-pressure turbine where it expands and is exhausted back to the boiler for reheating. The reheat steam flows to the intermediate-pressure turbine where it expands and is exhausted back to the boiler again for reheating. The second stage of reheated steam flows from the boiler to the reheat turbine where it expands and exhausts to the crossover line that provides the steam to the low-pressure turbine. The steam expands through the low-pressure turbine and exhausts to the condenser. Thus in the double-reheat cycle, high-, intermediate-, and low-pressure turbine designations are used as for the single-reheat cycle, with the addition of the reheat turbine designation for the turbine required for the second stage of reheat. This arrangement is shown in Fig. 2.15(E).

(a) Exhaust Conditions: Two designations exist based on the turbine exhaust conditions: condensing and noncondensing. These two designations are shown in Figs. 2.15(A) and (B). The condensing turbine exhausts to a condenser where the steam is condensed at sub atmospheric pressure (vacuum). The low pressure turbines of a typical power plant cycle are condensing turbines in that they exhaust to a steam surface condenser or to a direct condensing air-cooled condenser. The condensing turbines have large exhaust areas since the steam is expanded to low pressures, extracting as much of the useful energy as reasonably possible prior to being exhausted. Thelow pressures result in a large volume of steam, requiring a large exhaust area to minimize energy loss in the exhausting process. The noncondensing turbine exhausts the steam above atmospheric pressure into a line for supply to the boiler, another turbine, or a process. The high- and intermediate pressure turbines and the reheat turbines in the single- and double-reheat cycles described previously are noncondensing turbines. Turbines used in processes that first expand the steam through the turbine with the exhaust steam supplied to a heat exchanger or other process functions are of the noncondensing type. Because of the higher exhaust pressure, the noncondensing turbine exhaust area is significantly smaller than for a condensing turbine.(b) Flow DesignationThe turbine can also be described by the number of directions steam flows to exhaust from the turbine. The number of directions (paths) required depends on the amount of steam and the specific volume (pressure) of the steam. A single flow turbine has the steam flowing in one direction and exhausting at one end of the turbine. The steam enters the turbine and expands in one direction as shown in Fig. 2.15(A).Small nonreheat turbines, mechanical drive turbines, reheat cycle high-pressure, and reheat cycle intermediate-pressure turbines typically employ single direction flow.Double-flow turbines have two steam flow paths. The steam enters the center of the turbine and flows in two opposite directions as shown for the low-pressure sections in Figs. 2.15(D) and (E). This type of turbine is also called an opposed-flow turbine. Large reheat cycle high-pressure, intermediate-pressure, reheat, and low-pressure sections typically are double-flow turbines. Low-pressure turbines in power plant cycles of 150 megawatts (MW) and larger are typically double-flow turbines. Large unit low-pressure turbines are usually double-flow because of the low pressure, resulting in a large steam volume.

Flow designations of triple-flow, four-flow, six-flow, and eight-flow are also used. These designations typically apply to the low-pressure sections of power plants. A triple-flow designation indicates the use of one double-flow low-pressure turbine in combination with a single-flow low-pressure turbine, as shown in Fig. 2.15(F). Four-flow designation indicates the use of two double-flow low-pressure turbines as shown in Fig. 2.15(G). Six- and eight- flow designations indicate the use of three and four double-flow low-pressure turbines, respectively.

© Extraction Types

Turbines are also designated by the type of extraction involved, if any. During the expansion of the steam through a turbine, removing steam from an intermediate stage of the turbine is called an extraction. In most power plants, some steam is extracted from the turbine expansion process and supplied to heat exchangers for feedwater heating. This type of extraction varies in pressure and flow as a function of load. This variation is acceptable and therefore no effort is made to regulate the pressure. This type of extraction is called uncontrolled, simple, or nonautomatic extraction, and is shown in Fig. 2.15(H).Turbines supplying steam for process applications typically must supply steam at a constant pressure. Since the pressure available varies with load unless controlled, valving is included in the turbine steam expansion path to control the pressure. This valving restricts the flow to the downstream stages as required to maintain the pressure of the extraction stage. This type of turbine is called a controlled or automatic extraction turbine and is shown in Fig. 2.15(1). If several controlled extraction points are required in any one turbine, multiple internal control valves are provided. One controlled extraction would be called a single automatic extractionturbine; two would be called a double automatic extraction turbine. Some turbines have no extraction points and therefore are called nonextraction turbines. This type of turbine is shown in Fig. 2.15(A).

(d) Shaft Orientation

The overall steam turbine generator arrangement of a power plant is designated as tandem-compound or cross-compound on the basis of the shaft orientation. These two arrangements are shown in Fig. 2.16. The tandem-compound unit has all turbines and the generator in-line, connected to the same shaft. The turbines all drive the same generator and thus operate at the same speed. The cross-compound unit has two turbine generator alignments. This type of arrangement is used to increase turbine efficiency. The cross-compound arrangement typically consists of high-pressure and intermediate-pressure turbines operating at 3,600 rpm (for 60Hz country) driving a generator. The exhaust steam of the intermediate turbine crosses over to a low-pressure turbine that operates at 1,800 rpm, driving a separate generator. The low-pressure turbine operating at the slower speed allows the use of longer last-stage turbine blades with expansion to higher moisture percentages and less exhaust losses. These characteristics result in higher overall turbine efficiencies.Large cross-compound units in the 1,300-MW range with both shaft orientations operating at 3,600 rpm have been built. The dual-shaft arrangement is used to minimize shaft length and any single generator size.

(e) DesignationsPower plant steam turbines are typically designated by shaft orientation, number of low-pressure turbine steam flow paths, and the last-stage blade length of the low-pressure turbine. A turbine designated as TC4F30, for example, indicates a unit that is tandem-compound (TC) having two double-flow (4F) low-pressure turbines with 30 in. (76.2 cm) last-stage blade length. A CC2F23 indicates a unit that is cross-compound (CC) having one double-flow (2F) low pressure turbine with 23 in. (58.4 cm) last-stage blade length.The last two parts of the designations are related to the low-pressure turbine since low-pressure turbines are standard designs. The manufacturer’s custom design or adapt existing designs of the high-pressure, intermediate-pressure, and reheat turbines for each power plant project. A range of standard low-pressure designs exist and the optimum standard low-pressure design is used with the custom designed higher-pressure turbines. The low-pressure designs are designated by the length of the last-stage blades.The Japanese designation also includes the number of casings in the arrangement. A designation of TC2C2F23 indicates a tandem-compound (TC) unit having two casings (2C) and a double-flow (2F) low-pressure turbine with 23 in. (58.4 cm) last-stage blade length. If the unit is a reheat unit, the two casing designation indicates that the high-pressure and intermediate-pressure turbine are in the same casing (representing one casing designation) with the low-pressure turbine being the second casing.For small units in the United States, the casing designation is also included. The designation SCSF17 indicates a single casing turbine (SC) with a single-flow path (SF) and last-stage blade length of 17 in. (43.2 cm).

STEAM TURBINE ARRANGEMENT. Power generation in modern day is largely from fossil or nuclear feeds. For fossil plants, the turbines typically operate at 3,600 rpm in countries with 60 hertz (Hz) electrical systems and 3,000 rpm for 50 Hz electrical systems. The high main steam pressures allow the use of compact high-speed designs. While turbine arrangement can be tandem compound, some are cross compound as said earlier. Units typically are tandem-compound because the cross compound arrangement cannot be justified economically. The cross-compound units cost significantly more than tandem-compound units because of the need for separate generators and larger foundations. The use of reheat and number of turbines increases with the plant size. Main steam and reheat steam temperature are typically 1,000° F (537.8° C). Steam expansion in the turbine cycle is mainly in superheated steam with only the last one or two stages of the low pressure turbine expanding in saturated steam. Typically, the expansion in the low-pressure turbine is to a moisture content of 6% to 8%. For sizes up to 600 MW, the high-pressure and intermediate-pressure sections may be in a single casing with an opposed flow arrangement. Last-stage blade lengths vary from 17 to 40 in. (43.2 to 101.6 cm). The general turbine arrangements used in modern day power plants are summarized in Table 1b by listing the number of reheat stages, steam pressures, and turbine configurations as a function of the unit output while table 1c also gives the range. Figure 2.17 shows the typical steam expansion conditions for nuclear and fossil plants.

Table 1b-Turbine arrangement from general electric company.

Table 1c-Adapted from ASME/IEEE Joint Power Generation Conference, Oct. 1979. The turbine throttle steam temperature and pressure is however subject to economic considerations which affect the metallurgical limits of piping materials that include various fittings, valves and other accessories. General limits of steam temperature are 750 F (399 degrees C) for carbon steel, 850 degrees F (454 degrees C) for carbon molybdenum steel, 900 degrees F (482 degrees C) for 1/2 to 1 percent chromium - 1/2 percent molybdenum steel, 950 degrees F (510 degrees C) for 1-1/4 percent chromium - 1/2 percent molybdenum steel, and 1,000 degrees F (538 degrees C) for 2-1/4 percent chromium - 1 percent molybdenum. Throttle steam temperature is also dependent on moisture content of steam existing at the final stages of the turbine. Moisture content must be limited to not more than 10 percent to avoid excessive erosion of turbine blades

FIG 2.17 Typical expansion lines for nuclear and fossil turbines. (From General Electric Company. Used with permission.

STEAM TURBINE CYCLES

The cycle of a steam power plant is the group of interconnected major equipment components selected for optimum thermodynamic characteristics, including pressures, temperatures, and capacities, and integrated into a practical arrangement to serve the electrical (and sometimes by-product steam) requirements of a particular project. Selection of the optimum cycle depends upon plant size, cost of money, fuel costs, non-fuel operating costs, and maintenance costs. The function or purpose for which a plant is intended determines the conditions, types, and sizes of steam generators and turbine drives and extraction pressures. Various types of steam turbine cycles exist and they include the following:

(a) Simple Condensing Cycles. Straight condensing cycles or condensing units withuncontrolled extractions are applicable to plants or situations where security orisolation from public utility power supply is more important than lowest power cost.Because of their higher heat rates and operating costs per unit output, it is not likelythat simple condensing cycles will be economically justified for an independent power plant application as compared with that associated with public utility purchased power costs.(b) Controlled Extraction-Condensing Cycles and Back Pressure Cycles. Back pressure and controlled extraction-condensing cycles are attractive and applicable to a cogeneration plant, which is defined as a power plant simultaneously supplying either electric power or mechanical energy and heat energy.© Topping Cycle. The topping cycle consists of a high pressure steam boiler and turbine generator with the high pressure turbine exhausting steam to one or more low pressure steam turbine generators. High pressure topping turbines are usually installed as an addition to an existing lower pressure steam electric plant.

2.4.4 STEAM TURBINE COMPONENTS.

The details and names of components of a steam turbine vary by manufacturer and type (impulse or reaction). However, when several terms are used for a particular component or item, the most commonly used terms are given. The arrangement and cross-section drawings used here are for a reaction turbine. A typical 400-MW reheat, tandem-compound steam turbine generator perspective arrangement is shown in Fig.2.18, with side and plan views shown in Figs. 2.19 and 2.20 respectively.(1)ValvesMajor valves associated with the steam turbine are shown in Fig. 2.21. The functions and significant features of the valves are discussed in this section as they occur in the steam path flow.2.4.4.1 Main Steam Stop (Throttle) Valves. The steam from the steam generator flows to the main steam stop or throttling valves. The primary function of the stop valves is to provide backup protection for the steam turbine during turbine generator trips in the event the main steam control valves do not close. . A secondary function of the stop valves is to provide steam throttling control during startup.

2.4.4.2 Main Steam Control (Governor) Valves. The steam flows from the stop valves to the main steam control or governor valves. The primary function of the control valves is to regulate the steam

flow to the turbine and thus control the power output of the steam turbine generator. The control valves also serve as the primary shutoff of the steam to the turbine on unit normal shutdowns and trips.The control valves are normally mounted on a steam chest that receives steam from the stop valves. For some units, the stop and control valves are directly connected, one stop valve providing steam to one control valve. For the unit shown in Figs. 2.19 and 2.20, there are two steam chests, each having three control or governor valves mounted on top. Each control valve supplies steam to one section or arc of the high-pressure turbine first stage. The unit shown has six control valves, and therefore six steam lines (leads) from the steam chest to the high-pressure turbine section. Each lead supplies steam to one arc (a segment of the full 360 degrees; 60-degree arc, in this example) of the turbine's first stage.2.4.4.3 Reheat Stop and Intercept Valves. As shown in Fig. 2.21,the steam exhausted from the high-pressure turbine flows through the cold reheat lines to the reheater in the steam generator. The reheated steam then flows through the hot reheat piping to the reheat stop and intercept valves. The reheat stop and intercept valves function similarly to the main steam stop and control valves. The reheat stop valves offer backup protection for the steam turbine in the event of a unit trip and failure of the intercept valves to close. The intercept valves control unit speed during shutdowns and onlarge load swings, and protect against destructive overspeeds on unit trips. The need for these valves is a result of the large amount of energy available in the steam present in the high-pressure turbine, the hot and cold reheat lines, and the reheater. On large load changes, the main steam control valves start to close to control speed; however, energy in the steam present after the main steam control valves may be sufficient to cause the unit to overspeed. The steam after the main steam control valves could expand through the intermediate- and low pressure turbines to the condenser, supplying more power output than is required, causing the turbine to overspeed. The intercept valves are used to throttle the steam flow to the intermediate-pressure turbine in this situation to control turbine speed. The unit shown in Figs.2.19 and2.20 has two reheat stop and intercept valve assemblies. Each assembly is connected to the intermediate-pressure turbine through a separate steam lead that supplies steam to half the intermediate-pressure turbine first stage.

2.4.4.4 Ventilator Valves. During a unit trip, the closure of the main steam stop and control valves and of the reheat stop and intercept valves traps steam in the high-pressure turbine. During the turbine overspeed and subsequent coastdown, the high-pressure turbine blades are subject to windage losses from rotating in this trapped steam. The windage losses cause the blades to be heated. This heating, in combination with the overspeed stress, can damage the highpressure turbine. To prevent this, a ventilator valve is provided to bleed the trapped steam to the condenser. The ventilator valve is connected to one of the main steam leads between the main steam control valves and the high-pressure turbine, as shown in Fig.2.21. On some combined high pressure-intermediate-pressure turbines, the ventilator valve is connected to the steam seal between the two pressure sections. On a unit trip, the valve automatically opens, bleeding the trapped steam to the condenser. This bleeding action causes the trapped steam to flow through the high-pressure turbine, maintaining the high-pressure turbine temperature within acceptable limits by preventing heat buildup from the windage losses.

Fig 2.15A-I Turbine types. (Adapted from Power, June 1989. Used with permission of McGraw-Hill.)

Fig 2.16A-B Turbine shaft orientations. (Adapted from Power, June 1989. Used with permission of McGraw-Hill.)

Fig 2.18 Steam turbine generator arrangement (From Westinghouse Electric Corporation. Used with permission.)

Fig 2.19 Steam turbine generator general arrangement (side view). (From Westinghouse Electric Corporation. Used with permission.)

Fig 2.20 Steam turbine generator general arrangement (plan view). (From Westinghouse Electric Corporation. Used with permission.)

Fig 2.21 Typical power plant steam flow diagram.

Fig 2.22 Combined high-pressure/intermediate-pressure turbine longitudinal section. (From Westinghouse Electric Corporation. Used with permission.)

Fig 2.23

2.5 Turbine Stationary PartsThe major stationary parts of the steam turbine are mainly those associated with the casing of the various turbine sections.The combined high-pressure-intermediate-pressure turbine of the 400 MW units is shown in Fig. 2.22, with the low-pressure turbine shown in Fig. 2.23.2.5.1 High-Pressure-Intermediate-Pressure Turbine. Figure 2.22 shows an opposed flow, combined high-pressure intermediate- pressure turbine. This type of arrangement is used on units up to 600 MW to save space and cost. Separate high-pressure and intermediate-pressure shells are used on larger units because of the larger steam volumes requiring the use of separate high-pressure and

intermediate-pressure sections. The use of a single shell instead of two separate shells eliminates the intermediate casing seals, shaft couplings, and bearings. The opposed flow arrangement also helps in balancing axial thrusts. The steam flows to the high-pressure and intermediate pressure turbine sections are high-pressure, high-temperature flows. Outer and inner cylinders or casings contain the steam. 2.5.2 Low-Pressure Turbine. Like the high-pressure-intermediate- pressure turbine, the low-pressure turbine has an outer cylinder, inner cylinder, blade rings, and casing seals. Outer and inner cylinders are provided because of thermal considerations. The outer cylinder of the low pressure turbine is exposed to the vacuum pressure of the condenser. A section of the outer cylinder is the exhaust flow guide or hood that directs the steam from the last stage of rotating blades to the condenser. The zone nearest the turbine is supplied low-pressure steam that leaks into the condenser and to the other zone that is at a slight vacuum. This arrangement prevents drawing cool ambient air over the shaft, causing thermal stresses in the shaft and reducing the condenser vacuum. 2.5.2 Rotor AssemblyThe major components of a turbine rotor assembly are the shaft (rotor), the wheels, and the buckets or blades. 2.5.3 BearingsSteam turbines have journal bearings and thrust bearings. Journal bearings are at each end of each rotor to support the weight of the rotor. One thrust bearing typically is provided for the entire steam turbine to maintain the axial position of the rotor.2.5.4 Turning GearA turning gear rotates the turbine rotor at slow speeds before startup and just after shutdown. This minimizes the bowing of the rotor, which can cause uneven temperature distribution in the covers and bases of the turbine. The turning gear consists of an electric motor that gear drives the turbine generator rotor. It is normally used for rotors of turbine generators whose capacity are up to 12.5MW and above.

2.5.5 PedestalThe steam turbine generator support foundation of large units is called a pedestal. Larger units have low-pressure turbines that exhaust downward and have numerous steam lines connected to the turbines. This requires the installation of the steam turbine generator on an elevated pedestal. Two types of turbine pedestals are used: heavy reinforced concrete and steel.

General Steam Turbine Plant Economic Rules (Steam power plant, U.S.A military handbook, 2004). Maximum overall efficiency and economy of the steam turbine power cycle are the objectives of a satisfactory design. Higher efficiency and a lower heat rate require more complex cycles which are accompanied with higher initial investment costs and higher operational and maintenance costs but lower fuel costs.General rules to consider improving the plant efficiency are thus as listed:a) Higher steam pressures and temperatures increase the turbine efficiencies, but temperatures above 750 degrees F (399 degrees C) usually require more expensive alloy piping in the high pressure steam system.

b) Lower condensing pressures increase turbine efficiency. However, there is a limit where lowering condensing (back) pressure will no longer be economical, because the costs of lowering the exhaust pressure is more than the savings from the more efficient turbine operation.c) The use of stage or regenerative feedwater cycles improves heat rates, with greater improvement corresponding to larger numbers of such heaters. In a regenerative cycle, there is also a thermodynamic crossover point where lowering of an extraction pressure causes less steam to flow through the extraction piping to the feed water heaters, reducing the feedwater temperature. There is also a limit to the number of stages of extraction/feedwater heating, which may be economically added to the cycle.This occurs when additional cycle efficiency no longer justifies the increased capital cost.d) Larger turbine generator units are generally more efficient than smaller units.e) Multi-stage and multi-valve turbines are more economical than single stage or single valve machines.f) Steam generators of more elaborate design and with heat saving accessory equipment are more efficient.

2.6 ELECTRIC GENERATOR

An electric generator is a device that converts the mechanical energy of a prime mover e.g. a turbine to an electrical energy. It consist of at least one stationary part (stator) and one rotating part (rotor) Figure 2.24 gives the diagram of a typical electric generator and the main components.

There are three basic types of rotating electric generators: synchronous ac, induction ac, and rotating dc. Virtually all of the power generated by electric utilities and industrial turbine generators is supplied by synchronous ac generators. This type of generator includes an excitation system which is used to regulate the output voltage and power factor.Induction generators are squirrel-cage induction motors which are driven above synchronous speed. They do not have an excitation system and hence cannot control voltage or power factor. The system must supply the excitation. Induction generators are generally applied where relatively small waste energy or hydro potential exists; they are driven by a steam turbine, a gas expander, or a hydraulic turbine to recover the power in the energy stream. Rotating dc generators have been replaced almost entirely by static silicon rectifiers. The demand for rotating dc generators is limited to a few very special applications such as elevators and large excavators. The choice of this type of generators for power plant application comes with a high maintenance cost associated with the commutators and brushes of dc generators.

2.6.1 SYNCHRONOUS GENERATORSSynchronous machines (C. James Erickson, 2001) have a stator three-phase winding, and a rotor winding energized by a DC source that rotates at constant speed proportional to the ratio of the applied frequency and the number of poles. The magnetic pole of the rotor can be salient (salient-pole type is used almost entirely for slow and moderate-speed generators since this construction is the least expensive and permits ample space for the field ampere-turns) or non salient (used in high-speed turbo alternators because of the excessive windage and the difficulty of obtaining sufficient mechanical strength).

The fundamental principle of operation of synchronous ac generators is that relative motion between a conductor and a magnetic field induces a voltage in the conductor. The magnitude of the voltage is proportional to the rate at which the conductor cuts lines of flux. The most common arrangement is with a cylindrical electromagnet rotating inside a stationary conductor assembly. The electromagnet is called the field while the conductors constitute the armature. An external source of dc power is applied through the collector rings on the rotor. The flux strength and hence the induced voltage in the armature are regulated by the dc current and voltage supplied to the field. Alternating current is produced in the armature by the reversal of the magnetic field as north and south poles pass the individual conductors.Cooling is an important feature of a generator and goes a long way in determining the overall performance of the system. Synchronous ac generators are classified by their method of cooling and excitation system. The design chosen is determined by the type of prime mover driving the generator, the power required, and the operating duty (e.g., continuous versus intermittent operation, clean versus dirty environment).The various categories of synchronous generator include air cooled, water cooled and hydrogen cooled or combination types.Air-cooled generators are produced in two basic configurations: open ventilated (OV) (for generators approximately 2000KVA and smaller) and totally enclosed water-to-air-cooled (TEWAC). In the OV design, outside air is drawn directly from outside the unit through filters, passes through the generator, and is discharged outside the generator. In the TEWAC design, air is circulated within the generator and passes through frame-mounted, air-to-water heat exchangers. They are used for generators whose capacity is less than 50MW .Hydrogen cooling is employed in generator beyond 50MW .The increasing complexities of generators required for large power plants leads to more windage losses, hence the need for the introduction of a more efficient cooling system which is the use of hydrogen. Table 2 gives an overview of power of a synchronous generator is limited by its possible rotor dimension (mechanical stress) and allowable armature current (temperature) while table 2a gives the performance data for synchronous generators. Synchronous generators may also be classified according to the speed: (1) the slow-speed engine driven type; (2) the moderate-speed waterwheel-driven type; and (3) the high-speed turbine-driven type. In (1) the speed seldom exceeds 75 to 90 r/min, although it may run as high as 150 r/min.Waterwheel generators also have salient poles which are usually dovetailed to a cylindrical spider consisting of steel plates riveted together.Their speeds range from 80 to 900 r/min and sometimes higher, the speed rating of direct connected waterwheel generators decreases with decrease in head. It is desirable to operate synchronous generators at the highest permissible speed since the weight and costs diminish with increase in speed.Turbine-driven generators operate at speeds of 720 to 3,600 r/min. Direct-connected exciters, belt-driven exciters from the generator shaft, and separately driven exciters are used. In large stations separately driven (usually motor) exciters may supply the excitation energy to excitation bus bars. Steam-driven exciters and storage batteries are frequently held in reserve. With slow-speed synchronous generators, the belt-driven exciter is frequently used because it can be driven at higher speed, thus reducing the cost.

Fig 2.24

Typical generator cross-section. (From Westinghouse Electric Corporation. Used with permission.)

Fig 2.25 Synchronous generator (ABB)

Table 2 Synchronous generator limit

Table 2a performance data for synchronous generator

2.6.2 INDUCTION GENERATORThe stator of an induction generator is similar to that of a synchronous generator. The rotor differs from the synchronous generator rotor in that there is no excitation and the conductors are shorted together at the rotor ends by an annular ring. This arrangement resembles a squirrel cage, which lends its name to the type of winding.The induction generator supplies real power in kilowatts, which displace high-cost energy from the system. The imaginary power, kilovars, is drawn by the induction generator; it requires installed capability by some other device on the system, but consumes only a negligible amount of energy.An induction machine operates at synchronous speed at zero loads. The rotor turns at the same speed as the rotating flux field in the stator, and no lines of flux are cut. When a load torque is applied, the rotor speed drops off or “slips” until full torque is reached at 2 to 5 percent slip. As a generator, the driver must overspeed the generator by 2 to 5 percent to achieve full electric output. Induction generators cannot operate independently in an isolated system. They can only function in parallel with synchronous generators that regulate voltage and supply the kilovars necessary to overcome the lagging power of the induction generation.Induction generators are simpler and lower in initial cost than synchronous generators. They have been applied to recover power by expanding waste-gas streams and low-pressure steam. In some applications an energy-recovery turbine or expander drives an induction generator-motor and

another pump or compressor on the same shaft. The generator-motor can either supply or absorb torque when the power of the other two devices is out of balance.

2.63 DC GENERATORSThe operating principle of the dc generator is very similar to that of the ac generator. In the dc generator the field is located in the stator while the armature rotates, generating alternating current in the armature windings.The commutator and brushes provide a means of transferring the output from the rotor to the stator, as well as of mechanically rectifying the alternating current. The commutator is a wearing surface for the brushes. It consists of individual copper segmentsinsulated from each other by mica and connected to the armature windings. The armature windingconnections to the commutator and the brush spacing have to be carefully arranged so that brushes of opposite polarity contact windings which are 180 electrical degrees out of phase. Many dc generators driven by motors have been installed in industrial plants, such as steel mills, to provide power for variable-speed drives. However, the advances in static silicon rectifier dc power sources have reduced the market for dc generators primarily to replacement and repair parts, with very few new installations.

2.6.4 POWER FACTOR.An essential component of the generator is the power factor. This is the cosine of the angle between the voltage waveform and the current waveform in a single phase. It is denoted by cosØ and can be diagrammatically represented by Fig 2.26 below.

Figure 2.26Power factor ratings (DONALD L. BASHAM, P.E,2004) of steam turbine driven generators have been found to be 0.80 for ratings up to 15,625 kVA and 0.85 for 17,650 kVA air-cooled and 25,600 kVA to 32,000 kVA air/water-cooled units. Standard power factor ratings for gas turbine driven air-cooled generators usually are 0.80 for machines up to 9,375 kVA and 0.90 for 12,500 to 32,000 kVA. Power factors of large hydrogen cooled machines are standardized at 0.90. Power factor for salient pole generators is usually 0.80. Power factor lower than standard, with increased kVA rating are obtained at extra price.

2.7 CONDENSER

A condenser is a closed vessel in which steam is condensed by abstracting the heat and where the pressure is maintained below atmospheric pressure. Therefore, the function of the condenser are: (1) to condense the steam leaving the turbine, collect the condensate, and lower the turbine exhaust

pressure.(2) to produce a vacuum or desired back pressure at the turbine exhaust for the improvement of plant heat rate, (3) to condense turbine exhaust steam for reuse in the closed cycle, (4) to deaerate the condensate, and (5) to accept heater drains, makeup water, steam drains, and start-up and emergency drains. The condensing of the steam requires the condenser to remove the heat of vaporization from the steam and reject it. Condensers are designed to reject this energy directly into cooling water or directly into the atmosphere. Figure 2.27 depicts a typical condenser

2.7.1 TYPES OF CONDENSERCondensers are divided into water cooled or air cooled types. The water cooled condensers are further divided into two types: (a) direct contact type condenser, where the condensate and cooling water directly mix and come out as a single stream. (b) Surface condensers, which are shell and tube heat exchangers where two fluids do not come in direct contact and the heat released by the condensation of steam is transferred through the walls of the tubes into the cooling water continuously circulating inside them.Direct contact condenser. When (1) low investment is desired and (2) condensate recovery is nota factor, direct-contact condensers are effective. They are relatively simple to build and operate, are limited to sizes less than 250,000 lb of steam per hour. These can be of three types: Spray, barometric and Jet condenser.Spray condenser. In spray condenser, the steam is condensed as a result of cooling water being sprayed into the steam with a provision of steam jet air ejector to remove the non condensable gases. Part of the condensate from the condenser is circulated through dry cooling towers and returned to and sprayed into the condenserIn barometric condenser, the cooling water is made to fall in a series of baffles to expose large surface area for the steam to come in direct contact. The jet condenser utilizes the aspirating effect of a jet for the entrainment of non condensables and the consequent elimination of a separate air pump. In the usual direct-contact condenser, where steam and raw circulating water are mixed, the recovery of pure condensate is precluded; greater feed water makeup is necessary, and poorer vacuums are attained than with surface condensers. Direct-contact-condenser installations are not found in large plants, but there is some recent interest in their use with dry cooling towers (Heat Exchange Institute Standards for Direct Contact and Low Level Condensers, 2000).. Surface condenser are basically a shell and tube heat exchanger consisting of water boxes for directing the flow of cooling water to and from horizontal tubes. The tubes are sealed into fixed tube sheets at each end and are supported at intermediate points along the length of the tubes by tube support plates. They may have up to four pass configurations but are usually limited to one or two pass. Figure 2.28 shows the arrangement of different number of pass configuration for a surface condenser In a single pass condenser, the cooling water makes one passage from end to end, through the tubes. Single pass condensers have an inlet water box on one end and an outlet water box on the other end while two pass condensers have the cooling water inlet and outlet on the same water box at one end of the condenser, with a return water box at the other end. When a single pass condenser with the same number and size of the tubes and the same water velocity is compared with a two pass condenser, a single pass condenser requires twice as much water flow but results in half the water temperature rise and therefore lower condenser pressure. Thus a single pass condenser is better for overall plant efficiency and reduces thermal pollution but requires twice the water flow.

The condenser contains Water boxes which may be divided by a vertical partition and provided with two separate water box doors or covers. This arrangement requires two separate cooling water inlets or outlets or both to permit opening the water boxes on one side of the condenser for tube cleaning while the other side of the condenser remains in operation. Reheating Hotwell. The hotwell of a condenser is that portion of the condenser bottom or appendage that receives and contains a certain amount of condensate resulting from steam condensation. Unless the condenser is provided with a reheating hotwell (also commonly called a deaerating hotwell), the condensate, while falling down through the tube bundle, will be subcooled to a temperature lower than the saturation pressure corresponding to the condenser steam side vacuum. For power generation,condenser subcooling is undesirable since it results in an increase in turbine heat rate that represents a loss of cycle efficiency. Condenser subcooling is also undesirable because the condensate may contain noncondensible gases that could result in corrosion of piping and equipment in the feedwater system. Use of a deaerating hotwell provides for reheating the condensate within the condenser to saturation temperature that effectively deaerates the condensate and eliminates subcooling. Condensers should be specified to provide condensate effluent at saturation temperature corresponding to condenser vacuum and with an oxygen content not to exceed 0.005cc per liter of water (equivalent to 7 parts per billion as specified in the Heat Exchange Institute (HEI), Standards for Steam Surface Condenser, 1970). The various advantages of a surface condenser are as follows:1. The condensate can be used as boiler feed water.2. Cooling water of even poor quality can be used because the cooling water does not come in direct contact with steam.3. High vacuum (about 73.5 cm of Hg) can be obtained in the surface condenser. This increases the thermal efficiency of the plant.The various disadvantages of' the surface condensers are as follows:1. The capital cost is more.2. The maintenance cost and running cost of this condenser is high.3. It is bulky and requires more space.

Air cooled condenser: In an air-cooled condenser, the steam is condensed inside tubes whilecooling air flows over fins on the external surfaces. These tubes are arranged in the area where packing or fill would be arranged in a conventional cooling tower, and propeller fans supply airacross the tube surfaces. Turbine design back pressures are normally in the range of 5 in Hga when served by air-cooled condensers. The air-cooled condenser is used where adequate water is not available in sufficient quantities to permit the use of conventional cooling towers.The air-cooled condenser has both advantages and disadvantages. Among the advantages are that it minimizes water make-up requirements and eliminates cooling tower blowdown disposal problems, cooling tower freeze-up, tower vapor plume, and circulating water pollution restrictions. The disadvantages of the air-cooled condenser include higher condenser operating pressure (lower cycle efficiency), higher first cost, larger site, higher noise levels, and higher operating cost.There are two basic types of air-cooled condenser systems, as shown in Fig.2.29. These are the jet condenser with dry cooling tower arrangement, and the direct air-cooled condenser system. In the jet condenser with dry cooling tower, part of the steam condensate is cooled in a dry cooling tower. It is then returned to the condenser where it is sprayed into the steam flow, causing the steam to condense and collect in the bottom of the condenser.

In the direct air-cooled condenser, the steam is piped from the turbine exhaust direct to air-cooled steam coils. The steam condenses in the coils, the condensate draining to the bottom collection tank.The jet condenser/dry cooling tower has several advantages. The most prominent advantage is that the cooling tower may be located farther from the plant than the aircooled condenser. The large size of the steam duct and the need to maintain a low-pressure drop in this duct dictates that the air-cooled condenser be located as close to the turbine as possible. It also eliminates the cost of the large steam duct from turbine to condenser.The advantages of the air-cooled condenser are that it eliminates the cost of the jet condenser and the cost of the circulating water pumps and piping. It normally also produces slightly better condenser vacuum. In the air-cooled condenser, there is only one approach temperature involved, from air to steam. Although the use of air-cooled condensers in Nigeria has been very limited, the scarcity of water, the need for zero water discharge, and the better modern designs of this equipment indicate that more of these types of installations will be used in the future.

Fig 2.26 One-pass rectangular surface condenser.

Figure 2.27 Counterflow barometric condenser with two-stage air ejector. (Ingersoll-Rand Co.)

Fig 2.28

Fig 2.29 Air cooled condenser.

2.8 COOLING TOWER This is a structure used for reducing the temperature of water, by bringing it into contact with an air stream where a small portion of the liquid is evaporated and the major portion is cooled. Before the development of cooling towers, once through cooling ponds have been employed for plant heat removal. In a once-through circulating water system, water is taken from a body of water such as a river, lake, or ocean, pumped through the plant condenser, and discharged back to the source. A once-through circulating water system has two significant advantages. First, the relatively low temperature of most water sources used for oncethrough cooling makes this the most efficient cycle heat rejection system design. Second, the simple system arrangement typically makes once-through cooling the cycle heat rejection system design with the lowest capital and operating costs. The disadvantage of this system is that the heated water is discharged back to the original water source, where the added heat is gradually dissipated to the earth's atmosphere. However, it may take a long time for the source water temperature to return to normal, or a new equilibrium temperature may be reached at a level higher than the normal temperature as long as the plant is in operation . However, increasing environmental concerns and thermal pollution controls have caused the enactment of environment related legislation. This has discouraged the practice of once through cooling system in plant operation and has given way for cooling towers.

Cooling towers are either natural draft (atmospheric type) or mechanical-draft designs (William S. Lytle, P.E. 2004). The natural-draft design utilizes a large-dimension concrete chimney (height, 300 +/- ft) which operates on air density difference to induce air through the fill. They are either cross or counterflow designs. There is also a natural draft-fan assisted cooling tower type which is a hybrid design. The purpose of this design is to augment the airflow produced by fans with airflow produced by the stack effect of a natural draft tower. Because the fans assist in producing the required airflow, the cost impact of a large stack is reduced. Because the stack augments the airflow, fan horsepower requirements are reduced. If designed properly in temperate climates, the fans may need to be operated only during relatively short periods of high ambient wet-bulb temperatures and high wind loads. The fan-assisted natural draft cooling tower has many of the same advantages as the hyperbolic natural draft, such as the high air discharge which precludes potential problems with recirculation and interference. The tower is also smaller than the hyperbolic natural draft cooling tower, resulting in less visual impact on the surrounding area. The natural draft cooling tower has the following advantages (1) no electric power is required except for pumping head and (2) no mechanical equipment is necessary, reducing maintenance requirements. The disadvantages are (1) atmospheric towers have limited capacities, since they are solely dependent on ambient atmospheric conditions, (2) water loss as a result of high wind velocities can be appreciable, and (3) a rather high pumping head is required to allow for maximum air–water contact time.The large natural-draft hyperbolic cooling towers are found in utility power service e.g. in the United States where their performance is enhanced when wet bulb temperature is low and relative humidity is high ( temperate environment) .The economics of this plant design will not favour power plant in Nigeria owing to the pervasive tropical environment. Because of the size of these units, 500 ft (155 m) high and 400 ft (122 m) in diameter at the base, they are more practical when the circulating cooling water flow rate is about 200,000 gal/min and higher.In the mechanical-draft design, large-diameter fans driven by electric motors induce or force the air through the fill. Mechanical-draft cooling towers use either induced-draft (pulling air through cooling tower) or forced-draft (pushing air into cooling tower) designs. They can be of cross flow or

counter flow design. In all cooling towers, water is sprayed over the fill while air passes through the fill. Therefore, they can be designed for close control of cold-water temperature. The various cooling tower designs are indicated in figure 2.31

Fig 2.31 Cooling tower types. (a) Crossflow-Forced draft; (b) crossflow-induced draft; (c) hyperbolic or natural type

(d) Counterflow type

The purchase of a cooling tower for power plant is based on performance curves (Fig. 2.32) showing operation for various wet-bulb temperatures and cooling ranges. The investment for a cooling tower is essentially a matter of water flow and is influenced by approach, range, and wet bulb (Fig. 2.33). The cost evaluation should include consideration of tower frame and fill, fans, motors, basin and pump pit, pump head, fan horsepower, freight, labor, and erection. In the choice of a tower for a power plant, there should be coordinated study and evaluation of the turbine and condenser for best overall economy.The height of a field-erected induced-draft tower, from basin curb to fan deck, ranges from 8 to 50 ft; widths vary from 6 to 60 ft; lengths from 8 to 500 ft; fan-stack height between 2 and 15 ft.

Fig 2.32 Cooling tower performance. Design for 85_F cold water, 95_F hot water, 78_F wet-bulb temperature, 10_ range; 1,000-gal/min cell.

Fig 2.33

2.9 FUEL AND FUEL HANDLING FACILITIES.

2.9.1 FUEL OIL.

Crude oil has been the majour source of fuel oil for both industrial and utility applications. When crude is refined in a distillation column; various products are extracted including the heavy oils which form the base of the coumn. These are referred to as asphaltines, residuum, bottom of the barrel, residual oil, or bunker С oil. The heavy oil is usually sold to electric utilities, large industrial users, or as a bunker fuel for ships. Because of their high density (low API gravity) and relatively high pour point, point, heavy oils are usually heated to pump them from onsite storage tanks to the burner. Crude oil prices has been floating between $75 and $79 per barrel at the current international oil pool (Sept.—2010). It proffers excellent potential to have low generation cost of power. With an effective and time-tested technology of power generation with fuel oil operated steam based power plants; furnace oil will indeed be the preferred alternative for liquid fuel IPPs. Fuel storage, handling and transportation are far simpler and easy to establish. It is also expected that over a period of time, the most predictable and stable price levels will be for the furnace oil. It also gives the opportunity for having lower levels of import costs on account of fuel while using furnace oil. All these will help the government to keep the fuel import bills for the future at lower levels, which is desirable. Furnace oil being residual fuel has no other commercial use than combusting for energy generation purpose as compared to other fuel sources like naphtha, diesel which are far more costly to maintain.

2.9.2 FUEL OIL CHARACTERISTICS. It is common practice in refining petroleum to produce fuel oils complying with several specifications prepared by the ASTM and adopted as a commercial standard by the National Bureau of Standards (Table 4). Fuel oils are graded according to gravity and viscosity, the lightest being No. 1 and the heaviest No. 6. Grades 5 and 6 generally require heating for satisfactory pumping and burning. The range of analyses and heating values of the several grades of fuel oils are given in Table 5. The gross heating value, density, and specific gravity of various fuel oils for a range of APIgravities are shown in Fig.2.34. The abscissa on this figure is the API (American Petroleum Institute) gravity and sp gr at 60–60°F (15°C) represents the ratio of oil density at 60°F (15°C) to water density also at 60°F (15°C).Since equipment for handling and, especially, burning of fuel oil is usually designed for a maximum oil viscosity, it is necessary to know the viscosity characteristics of the fuel oil to be used. Figure 2.35 gives the standard ASTM chart for predicting viscosity of the oil at any other temperature

Table 4 ASTM Standard Specifications for Fuel Oils

No. 1: Distillate oil intended for vaporizing pot-type burners and other burners requiring this grade of fuel.No. 2: distillate oil for general purpose domestic heating for use in burners not requiring No. 1 fuel oil.No. 4: Preheating not usually required for handling or burning.No. 5 (Light): Preheating may be required depending on climate and equipment.No. 5 (Heavy): Preheating may be required for burning and, in cold climates, may be required for handling.No. 6: Preheating required for burning and handling.Recognizing the necessity for low-sulfur fuel oils used in connection with heat treatment, nonferrous metal, glass, and ceramic furnaces and other special uses, a sulfur requirement may be specifiedin accordance with the following format: The sulfur content of no. 1 and no. 2 fuel oil is limited to 0.5 percent (ASTM D396). The sulfur content of fuels heavier than no. 2 must meet the legal requirements of the locality in which they are to be used. The additional refinery processing needed by some residual fuels to meet low-sulfur-content regulations may lower the viscosity enough to cause the fuels to change the grade classification.Fuel oil used for domestic purposes or for small heating installations will have lower viscosities and lower sulfur content. In large-scale industrial boilers, heavier-grade fuel oil is used with sulfur content (ASTM D129 and D1552) requirements regulated according to the environmental situation of each installation and the local environmental regulations.The flash point (ASTM D93) is usually limited to 60_C (140_F) minimum because of safety considerations. Asphalting content (ASTM D3279), carbon residue value (ASTM D189 and D524), ash (ASTM D482), water content (ASTM D95), and metal content requirements are included in some specifications.

The pour point (ASTM D97), indicating the lowest temperature at which the fuel will retain its fluidity, is limited in the various specifications according to local requirements and fuel-handling facilities. The upper limit is sometimes 10_C (50_F), in warm climates somewhat higher.Another important specification requirement is the heat of combustion (ASTM D240). Usually, specified values are 10,000 cal/kg (gross) or 9,400 cal/kg (net). Because of economic considerations residual fuel oil has been replacing diesel fuel for marine purposes. Viscosity specifications hadto be adjusted to the particular operational use, and some additional quality requirements had to be allowed for.

Table 5 Range of Analyses of Fuel Oils

Transportation, Handling, and Storage. A worldwide system for distributing petroleum (and its products) has been developed because petroleum has a high calorific value per unit volume, is in easily handled liquid form, and has varied applications. The serious hazard inherent in possible oil-storage-tank failure is overcome by storing oil in underground tanks or by protecting surface tanks by surrounding them with cofferdams of sufficient capacity to hold the entire contents of any tank so protected. To facilitate pumping heavy fuel oil, heating equipment is usually provided in storage and transportation facilities

Fig. 2.34

Fig.2.35 Approximate viscosity of fuel oil at various temperatures.

2.9.3 Oil-Burning EquipmentThe burner is the principal component of equipment for firing oil. Burners are normally located in the vertical walls of the furnaces.Oil Burners. The most frequently used burners are the circular type. Figure 2.36 shows a single circular-register burner for gas and oil firing.The maximum capacity of the individual circular burner ranges up to 300 × 106 Btu/h (316 × 104 kJ/h). In order to burn fuel oil at the high rates demanded of modern boiler units it is necessary that the oil be atomized, i.e., dispersed into the furnace as a fine mist, to expose a large amount of oil particle surface to the air and ensure prompt ignition and rapid combustion.For proper atomization, oil of grades heavier than No. 2 must be heated to reduce viscosity to 135 to 150 SSU (Saybolt seconds universal). Steam or electric heaters are required to raise the oil temperature to the required level, i.e., approximately 135°F (57°C) for No. 4 oil, 185°F (74°C) for No. 5 oil, and 200 to 220°F (93 to 104°C) for No. 6 oil.Steam or Air Atomizers. Steam atomizers are the most widely used. In general they operate on the principle of producing a steam-fuel emulsion which, when released into the furnace, atomizes the oil through the rapid expansion of the steam..Steam atomizers are available in sizes up to 300 × 106 Btu/h input—about 16,500 lb (7500 kg) of oil per hour. Oil pressure is much lower than that required for mechanical atomizers.Maximum oil pressure can be as much as 300 lb/in2 (2040 kPa) and maximum steam pressure 150 lb/in2 (1020 kPa).The steam atomizer performs more efficiently over a wider load range than other

types. It normally atomizes the fuel properly down to 20 percent of rated capacity. A disadvantage of the steam atomizer is its consumption of steam. Mechanical Atomizers. In mechanical atomizers the pressure of the fuel itself is used as the means for atomization.The return-flow atomizer is used in many units where the use of atomizing steam is objectionable or impractical. The oil pressure required at the atomizer for maximum capacity ranges from 600 to 1000 lb/in2 (4080 to 6700 kPa), depending on capacity, load range, and fuel. Mechanical atomizers are available in sizes up to 180 × 106 Btu/h (190 _ 106 kJ) input—about 10,000 lb (4500 kg) of oil per hour.Excess Air. It is necessary to supply more than the theoretical quantity of air to ensure complete combustion of the fuel in the furnace. The amount of excess air provided should be just enough to burn the fuel completely in order to minimize the sensible heat loss in the stack gases. The excess air normally required for oil firing, expressed as percent of theoretical air, is generally between 5 and 7 percent

Fig 2.36 Circular register burner with water-cooled throat for oil and gas firing.

3.0 PUMPSA pump is a machine that imparts energy into a liquid to lift the liquid to a higher level, to transport the liquid from one Place to another, to pressurize the liquid for some useful purpose, or to circulate the liquid in a piping system by overcoming the frictional resistance of the piping system (Lawrence J. Seibolt, 1996)Pumps are used for many purposes and a variety of services: for general utility service, cooling water, boiler feed, and lubrication; with condensing water and sumps; as booster pumps, etc Turbines and boilers have increased in size, requiring larger boiler feed pumps. Although there are a variety of pumps found in a power plant, the basic steam power plant cycle includes a combination of a condensing and a feedwater heating cycle, and this requires a minimum of three pumps:1. A condensate pump that transfers the condensate from the condenser hot well into the deaerator2. A boiler feed pump that transfers feedwater from the feedwater heaters to the economizer or the boiler steam drum

3. A circulating water pump that provides cooling water through the condenser to condense the exhaust steam from the turbine. Pumps that are found in power plants come in a variety of sizes and designs that depend on the fluid and the service. From the Hydraulic Institute Standard, Figure 2.37 illustrates of types of pump. However, pumps are divided into two major categories: dynamic/centrifugal and displacement pumps (Herbert.B.Lammers, 1998)

1. Dynamic (kinetic) pumps are those in which energy is continuously added to increase fluid velocities. These pumps include centrifugal and regenerative pumps.2. Displacement pumps are those in which energy is added periodically by the application of force. These pumps include reciprocating and rotary-type pumps.Pumps also can be identified in four general classifications as follows:1. Reciprocating pumps. These include piston, plunger, and diaphragm pumps, and these can be of simplex or multiplex design.Power and vacuum pumps are also part of this classification. 2. Rotary pumps. These include gear, screw, and vane pumps.3. Centrifugal pumps. These include radial-flow, mixed-flow, and axial-flow pumps, and the designs can be single or multiple stage.4. Special pumps. These include jet, gas-lift, and hydraulic-ram pumps.

There are a great variety of pumps from which to make a selection, and each pump has its specific advantages that need to be analyzed for a specific application. The simplest pump is the injector or jet pump, which has been used on small boilers and portable units and has provided a low first cost and a simple design. Reciprocating pumps find ready acceptance, particularly in the smaller plant, where first cost is a factor. They are simple in construction, easy to repair, and reliable in operation. Rotary pumps find application in handling oil and lubricants. Centrifugal pumps are available for a variety of services and purposes having an almost unlimited range of industrial applications. They are widely used because of their design simplicity, high efficiency, wide range of capacity, head, smooth flow rate, and ease of operation and maintenance. The ultimate selection of pump type will largely depend on the following parameters: Capacity range of liquid to be moved, Differential head required, NPSHA (Net Positive Suction Head Available), Shape of head capacity curve, Pump speed, Liquid characteristics and Construction

Much work had been done over the years since the development of pumps. However, the scope of this study will be limited to pumps bothering on power plant application. These are kinetic/dynamic pumps. They are broadly divided into centrifugal and regenerative. As listed in Table 6, the most common type of kinetic pump used in a modern central power plant is the centrifugal pump. Centrifugal pumps include radial, axial, and mixed flow types, with the radial flow volute type used for the bulk of power plant applications. Regenerative pumps are typically referred to as vortex, peripheral, or turbine pumps. In most centrifugal pumps, liquid enters the pump through the impeller eye and is either thrown radially outward through an expanding pump casing, thrown outward along the impeller vane, is made to flow parallel to the axis or shaft of the pump or it is discharged both axially and radially into a volute type of casing as found in mixed flow pumps

The various types of centrifugal pumps include Volute type Centrifugal pumps, diffuser Type Centrifugal Pumps, axial Flow and Mixed Flow Centrifugal Pumps. A regenerative type of centrifugal pump has an impeller with vanes on both sides of a rim that rotates in a channel in the pump's casing. Liquid enters through a nozzle into an impeller vane and is forced outward by

centrifugal force. The liquid impacts the pump casing and is turned inward to reenter the impeller at a different vane. This cycle is repeated throughout the rotation of the impeller, generating pressure until the liquid is forced out of the pump at the discharge nozzle. Because of close running tolerances, the regenerative pump is suitable only for clear liquids with relatively low viscosities (less than 250 SSU). These pumps are useful in pumping liquids containing vapors and gases because of their resistance to cavitation.

Table 6 - Power Station Pump Applications

Figure 2.373.1 POWER PLANT PUMP APPLICATION

Power station pump applications can be divided into the following category:• Circulating water pumps,• Condensate pumps,• Boiler feed pumps, and• General service/slurry pumps. Circulating Water PumpsCirculating water pumps are high-capacity low-head pumps that provide the cooling water flow for the circulating water system. Because of their large size and continuous operation, they are carefully selected for economical and reliable operation over the lifetime of the plant.Circulating water pumps are typically selected from one of three pump designs: vertical wet pit, horizontal dry pit, and vertical dry pit pumps. For once-through circulating water systems (systems without cooling towers), vertical wet pit pumps are most commonly used, followed by horizontal dry pit pumps and vertical dry pit pumps, in that order. For closed cycle circulating water systems (systems with cooling towers), vertical wet pit and horizontal dry pit pumps are used about equally, with vertical dry pit pumps used less frequently. Vertical Wet Pit Pumps. Vertical wet pit pumps, as shown in Figs.2.38 IS typically of the mixed flow, single-stage, single-suction type for circulating water service. Axial flow pumps are occasionally used for very low- head applications. Vertical wet pit pumps use a vertical, internally lubricated shaft to drive the pump impeller. The pump is partially submersed in a wet pit with the motor mounted directly over the pump above the water level. Location of the motor directly above the pump column minimizes horizontal space requirements. Vertical wet pit pumps may be of pull-out or non-pull-out design. Pull-out design allows the rotating elements and critical nonrotating components such as the impeller shroud and pump bowl/diffuser/volute to be quickly removed without removing the column or disconnecting the pump discharge.Non-pull-out design has a 20% to 25% lower capital cost; however, pump disassembly is more difficult and requires a longer pump outage. Another design variable for vertical wet pit pumps is the location of the discharge relative to the baseplate. An abovefloor or aboveground discharge indicates that the pump dischargeis above the baseplate, whereas a below-floor or belowground discharge refers to the opposite. The belowfloor discharge is more difficult to disconnect since access to the discharge is usually limited. Because disconnecting the discharge is required for disassembly of non-pull-out pumps, below-floor discharge combined with non-pull-out design may create maintainability problems.In applications where large variations in water level exist, short column vertical wet pit pumps can be used to avoid the use of pumps with long column lengths. Horizontal Dry Pit Pump. For circulating water service, horizontal dry pit pumps are typically split-case, single-stage, double-suction type with either centrifugal or mixed flow design. Where horizontal space is limited, horizontal dry pit pumps can be installed in a vertical position with the motor above the pump. Vertical Dry Pit Pump. The pump is located in a dry pit below the water level, with suction taken from a suction tunnel located below the pump. The pump motor is above the pump, thus minimizing horizontal space requirements.

Vertical wet pit pump components—pullout design.

3.1.1 Circulating Water Pump Design Criteria. The selection of a circulating water pump for a specific circulating water system application requires an evaluation of several design criteria. Pump design criteria include pump capacity and total developed head, net positive suction head, submergence, suction specific speed, and rotative speed. Circulating Water Pump Selection: Several factors are considered in the selection of the type of circulating water pump to be used for a particular power plant application. . Some typical factors considered in the evaluation of water pump include the following: owner/operator experience, circulating water system configuration/site conditions, cost, space considerations and accessibility, pump type and arrangement, system design condition, operational requirements, guaranty, materials at construction and pump testing.

3.1.2 Condensate Pumps. Condensate pumps are medium flow medium-head pumps that pump condensate from the condenser hot well generally through a series of low-pressure feedwater heaters to a deaerating heater. These pumps operate at a very low pressure at their suction with cold condensate, which can lead to pump damage because of cavitation if the pumps are not carefully selected to allow for these severe operating conditions. They are available in both horizontal and vertical types. Years ago, typical condensate pumps used in central power stations were horizontal multistage centrifugal pumps because of their ease of installation, maintainability, availability, reliability, and operability. However, with the trend toward larger power stations, larger condensers, and lowered hot wells to reduce building costs, the NPSH available to the condensate pumps, already low, was reduced considerably more. As a result, the horizontal centrifugal condensate pumps have been replaced with vertical, multistage pumps, mounted in suction "cans" beneath the

plant ground floor. The suction "can" lengths are determined so that adequate NPSH is provided to the centerline of the first-stage impeller for proper operation of the condensate pump.Condensate pumps, as shown in Figs. 2.38, are motor-driven vertical, multistage, wet suction, "can" type pumps with either single- or double-suction first-stage impellers. The pumps are located near the condenser with the pump baseplates at approximately ground floor elevation and arranged for below-floor suction from the condenser hot well and for above-floor discharge. The drive motor is mounted directly above the condensate pump to minimize horizontal space requirements. The number and size of condensate pumps vary with each installation.Condensate Pump Design Criteria: The selection of a condensate pump requires the proper application and evaluation of several important condensate pump operating parameters and general guidelines. These include the pump capacity and total head requirements, net positive suction head, pump/suction can length, suction specific speed, peripheral velocity of the outer tip of the impeller inlet vanes, and piping system layout. The design point for condensate pumps is specified by the design capacity and total developed head.The design capacity for each condensate pump is determined by summing the condensate flow requirements for the following items:• Condensate flow requirements from the condenser hot well with the unit operation at maximum turbine heat balance conditions; typically 5% overpressure conditions with the turbine control valves wide open (VWO);• Condensate cycle makeup flow, typically 1% to 3% of the maximum condensate flow; Soot blowing steam flow, if applicable;• Auxiliary steam flow, if applicable;• Secondary air preheating flow, if applicable; and• Boiler feed pump seal water injection flow, if applicableA flow margin of 5% of the total flow determined above is typical to provide latitude for future increase in the flow requirements due to any of the contributing factors. The design total developed head for each condensate pump is calculated by determining the difference between the condensate pump discharge head and the suction head as shown in table 7 and 8 . A head margin of 5% of the total developed head determined is typical the shape of the condensate pump characteristic curve is important in vertical condensate pump designs. For stable parallel pump operation, the minimum rise in the pump curve from the design point should be 20% to 25%. The maximum rise should be approximately 40%. Lower rises to shutoff are acceptable if an independent minimum flow recirculation system is provided for each pump to guard against possible operation of a pump at or near shutoff conditions.The selection of a condensate pump is highly influenced by the configuration and overall space availability of the power station. As a result, condensate pumps are usually vertical multistaged units with below-floor suction cans and are located near the condenser. Two important condensate pump selection factors are the number of condensate pumps required and the type of pump flow control to be used. These two factors are determined during a detailed investigation and evaluation of the condensate system. Information regarding the planned plant operating characteristics (base loaded or peaking), pumping flexibility, and operator requirements are considered as well as the plant economics, equipment capital cost, and operation and maintenance costs..

Fig 2.39 Condensate pump—vertical, multistage, wet suction can type double-suction first-stage impeller.

Table 7- Condensate Pump Total Suction Head Determination

Table 8- Condensate Pump Design Total Developed Head Determination

3.2 BOILER FEED PUMPSAt the heart of the power station preboiler systems is the boiler feed pump. This is a pump that must be reliable and rugged to withstand not only continuous normal high-pressure pumping operation but also transient system upset conditions and possible frequent starting and stopping to match the plant's load output requirements (cycling operation).In general terms, a boiler feed pump is any pump that supplies feedwater to a steam generator for the production of steam either for energy conversion (supply to a steam turbine) or for plant or other industrial uses. Boiler feed pumps are available in many pump configurations and sizes and supply the flow and head required for any application. However, the scope of study shall be limited to boiler feed pumps that are diffuser or volute, horizontal, double-case barrel, single- and double-suction first-stage impeller, multistage centrifugal. pumps. This is the most common type of boiler feed pump used in central power station applications today. A typical boiler feed pump configuration is illustrated in Fig. 2.40.Many boiler feed pump system configurations have been used in power station applications. The basic system usually includes a deaerating heater and storage tank at some elevation above the suction of the boiler feed pump to provide a reservoir of heated, deaerated condensate to the boiler feed pump and available suction head for the pump. The suction pipeline to the boiler feed pump is amply sized to maintain the required suction velocity into the boiler feed pump, as well as limit the friction drop between the deaerator and the boiler feed pump.A booster boiler feed pump may be included to provide suction head to the main boiler feed pump. The booster pump may be motor-driven or driven by the main boiler feed pump driver through an extended shaft off the driver (usually a steam turbine) through reduction gearing. A single-suction first-stage impeller is usually used in the main boiler feed pump in this system.A conservative boiler feed pump system would also include a motor-driven startup boiler feed pump. This pump would be used primarily for plant startup activities, but could also be used to supplement the reliability and availability of the boiler feed system by operating in parallel with the main boiler

pump at reduced plant loads or even at design load, depending on the capacity and head available from the startup boiler feed pump. The discharge of the boiler feed pump should include pump recirculation instrumentation, valving, and piping back to the deaerator storage tank. Downstream, several stages of regenerative feedwater heating may be used, depending on the plant economics and cycle efficiency required. Some typical boiler feed pump systems are shown in Figs.2.41 and 2.42

Fig 2.40

Fig 2.41 Boiler feed pump system. One full-capacity boiler feed pump and startup/standby boiler feed pump

Fig 2.42 Boiler feed pump system. One full-capacity boiler feed pump with booster and startup/standby boiler feed pump

2 Boiler Feed Pump Design Criteria. The selection of a boiler feed pump is dependent on the requirements and constraints imposed by the boiler feed pump system configuration and operation. In addition to the development of system configuration, pump hydraulics, including the boiler feed pump capacity; total head, net positive suction head, transient operation, specific speed, and pump physical construction must be considered.The total developed head for the boiler feed pump is calculated as shown in Tables 9 and 10 by determining the difference between the boiler feed pump discharge head and suction head. A head margin of 5% of the total developed head determined is typical.

Table 9 Boiler Feed Pump Total Suction Head Determination

Table 10- Boiler Feed Pump Design Total Developed Head Determination

The parameter used to define the amount of suction head required above the vapor pressure is termed NPSH and is the total suction head less the vapor pressure. For a typical power plant installation, it is estimated that the maximum NPSH available (NPSHA) to the boiler feed pumps is approximately 130 to 145 ft depending on the elevation of the deaerator/deaerator storage tank. This value represents a maximum value, in that the length of the static column between the deaerator storage tank level and the boiler feed pump center line is at essentially the maximum practical length permitted by plant arrangement. The desirable maximum deaerator height is limited by the boiler building height (Hydraulic Institute Standards (1983).The boiler feed pumps are normally installed at the operating floor level, thereby fixing the lower end of the static column. Most boiler feed pumps are physically located in the plant in close proximity to the main turbine generator unit. The type and arrangement requirements of the pump(s) driver are normally specified.The following system design conditions are usually provided by a power plant engineer to the pump manufacturer:• Water chemistry, with the anticipated constituents of the boiler feed water, as well as pH range, to confirm or select the pump materials of construction.• Maximum developed head per stage. This is typically about 2,200 feet per stage, based on operating experience and EPRI recommendations.• Boiler feed pump suction conditions:—Design operating pressure at design conditions,—Minimum feedwater suction temperature,—Design feedwater operating temperature,—Design steady-state NPSH available,—Maximum NPSH available for sudden load reduction, and—Total boiler feedwater suction flow.

• Boiler feed pump discharge conditions:—Discharge design operating capacity,—Total head at design operating capacity,—Interstage bleedoff flow (if required), and—Interstage bleedoff discharge pressure.• Boiler feed pump speed range at design.• Maximum pump specific speed, typically 1,600 to 1,800.• Maximum suction specific speed required of first stage, recommended to be approximately 10,000 to 12,000.• Seal water temperature range.The actual NPSH available is generally determined with all low-pressure feedwater heaters in service, with no margin or contingency included. It is important that a boiler feed pump be selected with conservative margin between the NPSH required by the pump and the NPSH available from the pump suction system. A boiler feed pump with low NPSH requirements meeting the following criteria should be considered:1. The NPSH required by the boiler feed pump at the design operating conditions, based on 3% reduction in first-stage total head, should not be greater than the calculated NPSH available, divided by 1.8.2. The NPSH required during sudden load reduction, based on 3% reduction in first-stage total head, should not be greater than the calculated NPSH available during sudden load reduction with the highest pressure low-pressure feedwater heater out of service, divided by 1.3.

3.3 Power Plant Economic and Load Analysis.Studies have shown that power plant design and operation (Black and Veatch, 1996) is anchored on several factors of which the prime ones are load, utility, plant operating, reserve factor and plant capacity factor.1. Load FactorIt is defined as the ratio of the average load to the peak load during a certain prescribed period of time. The load factor of a power plant should be high so that the total capacity of the plant is utilized for the maximum period that will result in lower cost of the electricity being generated. It is always less than unity. High load factor is a desirable quality. Higher load factor means greater average load, resulting in greater number of power units generated for a given maximum demand. Thus, the fixed cost, which is proportional to the maximum demand, can be distributed over a greater number of units (kWh) supplied. This will lower the overall cost of the supply of electric energy.2. Utility FactorIt is the ratio of the units of electricity generated per year to the capacity of the plant installed in the station. It can also be defined as the ratio of maximum demand of a plant to the rated capacity of the plant. Supposing the rated capacity of a plant is 200 mW. The maximum load on the plant is 100 mW at load factor of 80 per cent, then the utility will be = (100 × 0.8)/(200) = 40%3. Plant Operating FactorIt is the ratio of the duration during which the plant is in actual service, to the total duration of the period of time considered.4. Plant Capacity FactorIt is the ratio of the average loads on a machine or equipment to the rating of the machine or equipment, for a certain period of time considered.

Since the load and diversity factors are not involved with ‘reserve capacity’ of the power plant, a factor is needed which will measure the reserve, likewise the degree of utilization of the CBM equipment. For this, the factor “Plant factor, Capacity factor or Plant Capacity factor” is defined as, Plant Capacity Factor = (Actual kWh Produced)/ (Maximum Possible Energy that might have produced during the same period

3.31 FACTOR AFFECTING POWER PLANT DESIGNFollowing are the factor effecting while designing a power plant.(1) Location of power plant(2) Availability of water in power plant(3) Availability of labour nearer to power plant(4) Land cost of power plant(5) Low operating cost(6) Low maintenance cost(7) Low cost of energy generation(8) Low capital cost

The cost of a power plant depends upon, when a new power plant is to set up or an existing plant is to be replaced or plant to be extended. The cost analysis includes:1. Fixed CostIt includes Initial cost of the plant, Rate of interest, Depreciation cost, Taxes, and Insurance.2. Operational CostIt includes Fuel cost, Operating labour cost, Maintenance cost, Supplies, Supervision, Operating taxes. INITIAL COSTThe initial cost of a power station includes the following:1. Land cost2. Building cost3. Equipment cost4. Installation cost5. Overhead charges, which will include the transportation cost, stores and storekeeping charges, interest during construction etc. Economy is the main principle of design of a power plant. Power plant economics is important in controlling the total power costs to the consumer. Power should be supplied to the consumer at the lowest possible cost per kWh. The cost of power generation can be reduced by, (i) Selecting equipment of longer life and proper capacities. (ii) Running the power station at high load factor. (iii) Increasing the efficiency of the power plant. (iv) Carrying out proper maintenance of power plant equipment to avoid plant breakdowns. (v) Keeping proper supervision as a good supervision is reflected in lesser breakdowns and extended plant life. (vi) Using a plant of simple design that does not need highly skilled personnel.Power plant selection depends upon the fixed cost and operating cost. Fuel is the heaviest items of operating cost in a steam power station. A typical proportion of generating cost for a steam power station is as follows:Fuel cost = 30 to 40%Fixed charges for the plant = 50 to 60%Operation and maintenance cost = 5 to 10%

The power generating units should be run at about full load or the load at which they can give maximum efficiency. In an electric power plant the capital cost of the generating equipment’s increases with an increase in efficiency. The benefit of such increase in the capital investment will be realized in lower fuel costs as the consumption of fuel decreases with an increase in cycle efficiency.

REFERENCES:

1. “Evaluated Weather Data for Cooling Equipment Design,” Fluor Products Co. Cooling Towers, Power, Mar. 1963. Baker and Shryock, 2. A Comprehensive Approach to the Analysis of Cooling Tower Performance, Trans. ASME, 1961.

3. Heat Exchange Institute Standards for Direct Contact and Low Level Condensers.

4 Sherwood,T. K., and R. L. Pigford: Absorption and Extraction, 2d ed., McGraw-Hill, New York, 1952, pp. 102–104.5. Kern,D.Q.: Process Heat Transfer, McGraw-Hill, New York, 1950.6 “Cooling Tower Performance Curves,” Blue Book, Cooling Technology Institute, Houston,Tex., 1970.7. Robert C. Rosaler (ed.), HVAC Systems and Components Handbook, 2d ed., McGraw-Hill, New York, 1998;8. CHAUDHRY, M. H. 1979. Applied Hydraulic Transients.

9. HENSLEY, JOHN C, EDITOR. 1985. Cooling Tower Fundamentals, 10 Li, KAM W. and A. PAUL PRIDDY. 1985. Power Plant System Design. John Wiley & Sons. New York, NY.

11. Black and Veatch,1996.Power Plant Engineering12. J.Edward Pope, 1997.Rule of Thumb for Mechanical Engineer.

13. A.K Raja.2006. Power Plant Engineering.

CHAPTER 3

METHODOLOGY

3.1 IINTRODUCTIONChapter three of this project focuses on the design parameters, process and equipment selection as well as economic considerations and justifications for the design of a 200MW oil fired power plant. Considerations will be given to suitable choice of power plant site selection and source of fuel and water requirements. The process design and selection of steam turbine, boiler, condenser and boiler feedwater pumps shall be discussed. Ancilliary equipment such as cooling towers, air heaters, feedwater heaters and fuel selection/flue gas handling equipment will also not be spared. Power plant software (steam/thermo flow) which shall take into account the various process parameters will be used to simulate the process equipment. The steam turbine design and selection will form the basis of the power plant design.In order to design a 200MW power plant, I intend to base my design on the selection of four-100MW turbine generators. The process will operate on a stand alone cycle arrangement with each power plant cycle churning out a maximum continuous load of 100MW and a combined capacity of 400MW.The additional capacity of 200mw (two-100mw team turbine) is based on the need to make provision for two standby spares in the event of failure of one of the process line and one power plant for future expansion consideration.The cogeneration power plant which involves a controlled condensing/extraction cycle option will be adopted in the power plant scheme. This will, in addition to being able to generate a combined capacity of 200mw, will also supply extracted steam for process heating, prime mover operation and utility services. Though the cycle is relatively more expensive than other forms like straight condensing type in terms of installation cost, the lower operational and maintenance cost coupled with higher plant output will proffer the economic justification of such choice.

3.2 Steam turbine designThe steam turbine design and selection process shall consider the following items:

Turbine Generators. Turbine generators shall be designed and selected in accordance withoutlined procedures. The turbine shall be of the controlled extracting/condensing type. The following are the major process parameters which must be made for a condensing turbine in a regenerative cycle using superheated inlet steam.

1) HP turbine throttle temperature.2) HP turbine throttle pressure.3) HP turbine exhaust pressure.4) HP turbine first stage pressure.5) IP Turbine throttle temperature.6) IP Turbine throttle pressure.7) LP Turbine throttle temperature.8) LP Turbine throttle pressure.9) LP Turbine exhaust pressure.10) Generator output.

11) Generator hydrogen pressure.12) Generator power factor.13) Boiler feed pump discharge temperature.14) Boiler feed pump discharge pressure.15) Superheater spray flow.

16) Highest pressure feedwater heater feedwater inlet temperature.17) Highest pressure feedwater heater feedwater outlet temperature.18) Highest pressure feedwater heater drains outlet temperature.19) Highest pressure feedwater heater extraction temperature.20) Highest pressure feedwater heater extraction pressure.21) Feedwater flow to boiler.22) Feedwater pressure at boiler inlet.

b) As a result of calculations based on above methods, the following design parameters can be quantified.1) Maximum capability of steam turbine.2) Heat rate.3) Enthalpy-drop efficiency.4) Type of turbine

APPLICABLE EQUATIONS

TSR (lb/KWh) = 3412.142(Btu/KWh)/AE (Btu/lb)

TSR (Kg/KWh) = 3600. 00(Kj/KWh)/AE (Kj/Kg)ASR= TSR/ ʅT

REQUIRED STEAM FLOW= ASR*TURBINE GENERATOR POWER OUTPUT (KW) in lb/h

The table below gives the theoretical steam rate from ASME standards

3.3 Steam Generators. Steam generators design shall employ the input/output method.

Input/Output Methoda) The following are the major parameters which must be made for input/output method.1) Fuel oil flow.2) Higher heating value.3) Combustion air temperature.4) Feedwater flow.5) Feedwater temperature.6) Feedwater pressure.7) Superheat desuperheat spray flow.8) Superheat desuperheat spray temperature.9) Superheat desuperheat spray pressure.10) Sootblowing steam flow.

11) Main steam temperature.12) Main steam pressure.13) Flue gas temperature at air heater outlet14) Flue gas oxygen at economizer outlet15) Drum pressure

b) As a result of the calculations based on above methods, the following design parameters can be quantified.1) Steam generator efficiency.2) Steam generator flow.3) Steam temperature and control range.4) Boiler capacity.5) Water and steam side pressure drop.6) Exit flue gas temperature

In addition to these parameters, a fuel ultimate analysis, fuel heating value, and ash (if any) heating values will be required.

3.4 Condensers. Condensers shall be designed in accordance with listed steps.a) The following are the major parameters for consideration.

1) Circulating water flow.2) Condenser pressure.3) Condenser inlet cooling water pressure.4) Condenser inlet cooling water temperature.5) Condenser outlet cooling water pressure.6) Condenser outlet cooling water temperature.7) Condenser absolute pressure.b) As a result of calculations based on above method, the following parameters can be quantified.1) Condenser tube cleanliness factor.2) Condenser tube fouling factor.3) Condenser waterside pressure drop.4) Condenser heat load.5) Condenser type

3.4.1 APPLICABLE EQUATIONS FOR CONDENSER DESIGNS _ condenser tube surface area, ft2Cc _ cleanliness factorC1 _ heat-transfer-rate constantCm _ material and gage factor –Table 9Ct _ water temperature correction factor-table 10cp _ specific heat, Btu/lb, _FG _ circulating-water quantity, gal/minh _ enthalpy, Btu/lbhr _ heat rejected by steam, Btu/lbL _ length of water travel (active tube length), ft

NPSH _ net positive suction head, ftOD=tube outside diameter, inQ _ heat transferred, Btu/hR _ temperature rise (to _ti), _FTDH _ total dynamic head, ftt _ tube wall thickness,TTD _ terminal temperature difference _ ts _ toti _ inlet-water temperature, _Fto _ outlet-water temperature, _Fts _ saturation temperature in condenser, _FUo _ overall heat-transfer rate, Btu/(ft2 _ h _ _F)V _ water velocity, ft/sWs _ steam to be condensed, lb/h_tm _logarithmic mean temperature difference, _FP=design pressure lb/in2

For condenser sizing, table 9 and 10 shall be consulted for steam flows to the condenser with the corresponding turbine throttle condition and the normal recommended condenser pressure and circulating water temperature. The heat rejected to the condenser will be taken as 950 Btu/lb of steam for nonreheat turbines and 975 Btu/lb for reheat machine.

Tube characteristics.

Material and gage factor

Inlet water temperature correction factor.

3.8 Feedwater heater; Feedwater heaters and auxiliary cooling water heat exchangers shall be designed based on the following parameters:Closed Feedwater Heaters.1) Feedwater flow.2) Feedwater inlet temperature.3) Feedwater outlet temperature.4) Feedwater inlet pressure.5) Feedwater outlet pressure.6) Drain inlet flow (where applicable).7) Drain inlet pressure (where applicable).8) Drain inlet temperature (where applicable).9) Drain outlet flow.10) Drain outlet temperature.11) Drain outlet pressure.12) Extraction steam flow.13) Extraction steam temperature.14) Extraction steam pressure.15) Heater pressure.In addition to these parameters, the heater manufacturer's design data will be considered.b) As a result of calculations based on above methods, the following parameters can be determined.1) Terminal temperature difference.

2) Feedwater temperature rise.3) Drain cooler approach (where applicable).4) Feedwater pressure drop.5) Pressure drop through drain cooler (where applicable). PARAMETERS FOR CONSIDERATION FOR FEEDWATER HEATERA _ heat-transfer surface, ft2Cm _ material and gage correction factor, Table 9D _ tube ID, in, Table 10d _ OD of tube, in ( and in are most common)F1 _ friction factor, Table 11F2 _ water-temperature correction factor, Table 12h _ enthalpy, Btu/lbk _ tube diameter and gage factor, Table 13L _ active length of tubes per pass, ftN _ number of passesn _ number of tubesP _ design pressure, lb/in2p _ pressure, lb/in2Q _ total heat transferred, Btu/hS _ allowable design stress at tube design temperature, lb/in2, from ASME Codet _ wall thickness, in (see Table 14); temperature, _FUo _ overall heat-transfer rate, Btu/(h _ ft2 _ _F) (the material correction factor, Table 15, will be applied to the overall heat-transfer rate)V _ water velocity, ft/sW _ steam flow, lb/hWw _ feedwater flow, lb/h_p _ pressure drop, lb/in2

Active tube length (L) = 500AV / (N Vk),n = 3.82A/ (Ld) Pressure drop, ∆p = (L + 5.5D)F1CtN/D1.24.

. The choice of tube diameter and material will be made from table 15 in accordance to the ASME Boiler and pressure vessel code. Tube thickness is calculated by the given equation:

---------------------------------------------------

Q= UA ∆ tm= Ww(h3- h2) = Ws∆hs----------

Table 9-material and gage factor

Table 10- tube internal diameter from feedwater heater tube constants

Table 11-friction factor

Table 12-water temperature correction factor.

Table 13-tube diameter and gage factor

Table 14-tube wall thickness

Table 15-tube material selection.

3.5 Cooling Towers. Cooling towers shall be designed in accordance with the given procedure.There are two methods for evaluating the performance of a cooling tower: the characteristic curve method and the performance curve method. Both methods require the same data and calculate the same performance parameter.The following are the major parameters which must be considered.a) Wet bulb temperature at tower inlet.b) Dry bulb temperature.c) Cold water temperature.d) Hot water temperature.e) Cooling water flow.f) Fan power.g) Makeup water temperature.h) Makeup water flow.i) Blowdown temperature.j) Blowdown flow.As a result of calculations, it should be possible to make a choice of cooling tower and to quantify the cooling tower capability as a percent of design.

3.7 Pumps. Centrifugal pumps shall be the favoured choice for process pumps because of its large volume capacity (condensate, circulating and boiler water feed pump) and it shall be designed in accordance with the prescribed steps.a) The following are the major parameters which must considered for each pump.1) Inlet flow.2) Inlet temperature.3) Inlet pressure.4) Discharge flow.5) Discharge temperature.6) Discharge pressure.7) Bleedoff flow.8) Bleedoff temperature.9) Bleedoff pressure.10) Pump input power.11) Pump speed.b) As a result of calculations based on above methods, the following pump parameters should be able to be determined for pump selection.1) Capacity.2) Pump total head.3) Pump power.4) Pump efficiency.5) Suction requirements.6) Available net positive suction head.7) Specific speed.

Air Heaters. The regenerative air heaters shall be used in accordance with the outlined procedures.a) The following are the major parameters which must be made for each air heater.1) Flue gas inlet temperature.2) Flue gas outlet temperature.3) Air inlet temperature.4) Air outlet temperature.5) Air inlet flow.6) Air outlet flow.7) Flue gas inlet flow8) Flue gas outlet flow.9) Flue gas side inlet and outlet static pressure.10) Flue gas side inlet and outlet velocity pressure.11) Air side inlet and outlet static pressure.12) Air side inlet and outlet velocity pressure.13) Inlet flue gas analysis (CO2, CO, O2).14) Outlet flue gas analysis (CO2, CO, O2).15) Fuel flow (calculated by steam generator output and efficiency).b) In addition to these measured parameters, a fuel ultimate analysis is required.